PHMSA's Proposed Rules for Natural Gas: Breaking Down the Regulations and Their Impact Across Gathering and Transmission Systems

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1 PHMSA's Proposed Rules for Natural Gas: Breaking Down the Regulations and Their Impact Across Gathering and Transmission Systems Texas Gas Association November 11, 2016

2 Disclaimer Discussion and information contained within this material is my personal opinion and not that of my clients or the companies we represent. Information regarding many of these issues is fluid and evergreen and no action should be taken on an issue unless directed through an official regulatory document or final rule.

3 Natural Gas Transmission & Gathering Rulemaking Docket number: PHMSA Significant: Yes Advanced notice: August 25, 2011 Proposed: March 17, 2016 Finalized: It depends on who you ask Commenters: 300+

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5 Most Significant Proposed Regulatory Changes 1. Additional reporting 2. Expansion of gathering regulations to larger diameterhigh-pressure pipeline 3. Removal of grandfather provision 4. Reliable, traceable, verifiable, and complete (RTVC) records 5. Integrity verification process requirements (IVP) 6. Spike hydrostatic testing 7. Creation of Moderate Consequence Areas (MCAs) 8. Expansion of existing integrity management program requirements 9. Corrosion mitigation 10. Repair criteria

6 Proposed Reporting Transmission Requirements Exceedance of MAOP that exceeds margin allowed with 5 calendar days Gathering Annual and safety-related conditions reporting for regulated and non-regulated gathering entities MAOP exceedance reporting when MAOP that exceeds margin allowed

7 General Definitions Close interval survey Legacy pipe and legacy construction technique Modern pipe Occupied site Significant seam cracking Transmission pipeline

8 Gathering Require reporting for all regulatory requirements - repealing exemption for all gas gathering line operators to report incidents, safety related conditions, and annual pipeline data Repeal use of API RP 80 for determining gathering lines and add new/revised definitions for: production facility or production operation gathering line Extend regulatory safety requirements to Type A lines in Class 1 locations that are 8 or greater in diameter Indirect prohibition on composite pipe

9 Definitions Relating to Gathering Gas Processing Plant Gathering line (onshore) Farm taps Onshore production facility

10 RP 80 Production operation means piping and equipment used for production and preparation for transportation or delivery of hydrocarbon gas and/or liquid and includes the following processes: (a) extraction and recovery, lifting, stabilization, treatment, separation, production processing, storage and measurement of hydrocarbon gas and/or liquids; and (b) associated production compression, gas lift, gas injection, or fuel gas supply. Additional definitions explaining the meaning of many of the terms used in this definition are found in 2.4. Basic production operations definitional concepts are presented below in Representative application of the production operations definition are shown and discussed in Appendix B.

11 Proposed Production Facility of Onshore Production Operation Wellbores, equipment, piping, and associated appurtenances confined to the physical acts of extraction or recovery of gas from the earth and the initial preparation for transportation. Preparation for transportation does not necessarily mean the gas will meet pipeline quality specifications as may be commonly understood or contained in many contractual agreements. Piping as used in this definition may include individual well flow lines, equipment piping, and transfer lines between production operation equipment components. Production facilities terminate at the furthermost downstream point where: 1) measurement for the purposes of calculating minerals severance occurs; or 2) there is commingling of the flow stream from two or more wells.

12 Proposed Production Facility of Onshore Production Operation Today, gathering terminates at the furthermost downstream of the following locations: (A) the inlet of the first downstream natural gas processing plant (B) the outlet of the furthermost downstream gathering line gas treatment facility, (C) the commingling of gas from separate production fields, the fields may not be more than 50 miles from each other (D) the outlet of the furthermost downstream compressor station used to increase gathering line pressure for delivery to another pipeline, or (E) the connection to another pipeline downstream of: (i) the furthermost downstream endpoint identified in (A), (B), (C) or (D), or (in the absence of such endpoint) (ii) the furthermost downstream production operation; or (the pipeline) transport gas from a point other than in a production operation exclusively to points in or adjacent to one or more production operations or gathering facility sites for use as fuel, gas lift, or gas injection gas within those operations; and does not include a natural gas processing plant.

13 Proposed Gathering Line (Onshore) A pipeline, or a connected series of pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of the following endpoints: 1. The inlet of 1st gas processing plant, unless the operator submits a request for approval to the Associate Administrator of Pipeline Safety that demonstrates, using sound engineering principles, that gathering extends to a further downstream plant other than a plant located on a transmission line and the Associate Administrator of Pipeline Safety approves such request; 2. The outlet of gas treatment facility that is not associated with a processing plant or compressor station; 3. Outlet of the furthermost downstream compressor used to facilitate delivery into a pipeline, other than another gathering line; or 4. The point where separate production fields are commingled, provided the distance between the interconnection of the fields does not exceed 50 miles, unless the Associate Administrator of Pipeline Safety finds a longer separation distance is justified in a particular case (see 190.9).

14 Proposed Incidental Gathering Gathering may continue beyond the above endpoints to the point gas is delivered into another pipeline, provided that it only does the following: It delivers gas into another gathering line; 1. It does not leave the operator s facility surface property (owned or leased, not necessarily the fence line); 2. It does not leave an adjacent property owned or leased by another pipeline operator s property where custody transfer takes place; or 3. It does not exceed a length of one mile, and it does not cross a state or federal highway or an active railroad; or It transports gas to production or gathering facilities for use as fuel, gas lift, or gas injection gas.

15 Current Requirements Type A (MAOP > 20% of SMYS) Type B (MAOP < 20% of SMYS) Subpart A- General Yes Yes Subpart B- Materials Yes Yes Subpart C- Pipe Design Yes Yes Subpart D- Design of Pipeline Components Yes Yes Subpart E- Welding of Steel in Pipelines Yes Yes Subpart F- Joining of Materials other than by Welding Yes Yes Subpart G- General Construction Requirements for Transmission Lines Subpart H- Customer Meters, Service Regulators and Service Lines Yes Technically Subpart I- Requirements for Corrosion Control Yes Yes Subpart J- Test Requirements Yes Yes Subpart L- Operations Yes 614, 616, 619, 703(c), 706, and 707 Subpart M- Maintenance Yes No Subpart N- Qualification of Personnel Modified No Subpart O- Integrity Management No No Yes No

16 Proposed Requirements Type A, Type 1 (MAOP > 20% of SMYS) Type A, Type 2 (MAOP > 20% of SMYS and 8 or greater) Type B (MAOP < 20% of SMYS) Subpart A- General Yes, except.13 Yes Yes Subpart B- F Materials, Pipe Design, Design of Pipeline Components, Welding of Steel in Pipelines, Joining of Materials other than by Welding Subpart G- General Construction Requirements for Transmission Lines Subpart H- Customer Meters, Service Regulators and Service Lines Subpart I- Requirements for Corrosion Control Yes Yes Yes Yes, except.319 Yes Yes Technically No No Yes, except.461(f),.465(f),.473(c), and.478 Subpart J- Test Requirements Yes Yes Yes Subpart L- Operations Yes.614, ,.619,.703(c),.706, and.707 Subpart M- Maintenance Yes, except.710 and.713 Yes No Yes.614,.616,.619,.703(c),.706, and.707 Subpart N- Qualification of Personnel Modified No No Subpart O- Integrity Management No No No No

17 Recordkeeping Reliable, traceable, verifiable and complete Must acquire and retain records standard Life of pipeline requirements including: Original steel pipe manufacturing records- tests inspections and attributes Plastic pipe design standard to withstand external pressures and loads Manufacturing standards and pressure ratings for valves. Flanges, fittings, branch connections, extruded outlets, anchor fittings and other components with material yield strength of 42,000 psi or greater must have manufacturing specifications including yield strength, ultimate tensile strength and chemical composition of materials. Welding and pipe joining qualification Coating repairs

18 Corrosion Assessment of recently installed installed or repaired pipe to ensure integrity of coating through DCVG or ACVG and make repairs in accordance with NACE standards Repair of external corrosion promptly, but not to exceed the next monitoring cycle Close interval surveys required when cathodic protection levels beyond required levels Program to address interference currents Detect the presence of any level of any electrical stray current Analysis of survey to determine cause Implementation of remedial cause to protect the segments Monitoring and mitigation program to identify corrosive constituents in the gas Entry point of constituents Product sampling Means by which effectiveness will be determined

19 Hydrostatic Spike Test Pipes operating at > 30 percent of SMYS with integrity threats Baseline pressure at least eight (8) hours Within 2-hours of stabilization, pressure must be raised to 1.50 times MAOP or 105 percent of SMYS and held for 30 minutes If threat is time dependent then periodic retesting is required Operators may elect to use alternative technology or evaluation process with approval from Administrator

20 Material Verification Process Applies to pipelines: Without RTVC records and constructed prior to enactment Located in HCA or Class 3 or 4 Prepare a material documentation plan Procedures for: Conducting non-destructive testing, examination and assessment for all above ground pipe Destructive testing on buried pipe for replacements or relocations of pipe removed from service Non-destructive or destructive testing for all excavators for anomaly direct examinations, repairs, maintenance, etc. Defining populations of unique combination of attributes Each population set must be tested through minimum number of examinations

21 Material Verification Process Tests must determine: Diameter Wall thickness Yield strength Ultimate tensile strength Charpy v-notch toughness Chemical properties Seam type Coating type Presence of stress corrosion cracking or selective seam weld corrosion using ultrasonic, magnetic particle, liquid penetrant or other non-destructive techniques

22 Material Verification Process Additional parameters: Minimum number of test locations What tests must be conducted in circumferential quadrant of the pipe for both non-destructive and destructive testing location Criteria for additional testing if material properties are not consistent with expectations Manner to document ANSI rating and material grade of components

23 MAOP Verification - Applicability Targeting pipes with a combination of: Operational condition Reportable in-service incident since last successful test due to certain events Presure test records are not RTVC Location High consequence area Class 3 or 4 Moderate consequence area the can accommodate inspection through ILI

24 MAOP Verification - Deadlines Plan within 1-year of effective date 50 percent completion within 8 years Remaining 50 percent within 15 years Operators may petition for extension

25 MAOP Verification Methods Optio n Methodologies General Overview 1 Pressure Test MAOP will be established to the pressure test divided by 1.25 or the applicable class location factor 2 Reduction in MAOP MAOP not greater than highest operating pressure during last 18 months divided by 1.25 or applicable class location factor 3 Engineering Critical Assessment ECA to establish material condition of segment and MAOP 4 Pipe Replacement Replace the pipeline segment 5 Pressure Reduction for Segments with Small PIR and Diameter 6 Alternative Technology MAOP < 30% of SMYS and PIR < 150 feet with diameter 8 inches and cannot be ILI or pressure tested reduce MAOP to pressure divided by 1.1, conduct direct assessment, examinations for cracking, monthly patrols, leakage surveys, odorization, potentially establish estimate for life of pipeline Process that provides sound engineering basis. Notification of PHMSA 180 in advance and receive no objection letter

26 Non-Integrity Mangement Areas Assessment Moderate Consequence Areas (MCAs) within a potential impact circle, as defined in , containing five (5) or more buildings intended for human occupancy, an occupied site, or a right of way for a designated interstate, freeway, expressway, and other principal 4- lane arterial roadway as defined in the Federal Highway Administration s Highway Functional Classification Concepts, Criteria and Procedures, and does not meet the definition of high consequence area, as defined in

27 Non-Integrity Mangement Areas Assessment The length of the MCA extends axially along the length of the pipeline from the outermost edge of the first PIR that contains either an occupied site, five (5) or more buildings intended for human occupancy, or a right-of-way for a designated interstate, freeway, expressway, or other principal 4-lane arterial roadway, to the outermost edge of the last contiguous PIR that contains either an occupied site, five (5) or more buildings intended for human occupancy, or a right-ofway for a designated interstate, freeway, expressway, or other principal 4-lane arterial roadway

28 Non-Integrity Mangement Areas Assessment Applicable to Class 3 and 4 Locations and MCAs Periodic assessments every 20 years, or shorter if anomaly Assessments must be capability of identifying anomalies and defects associated with each threat the pipeline is susceptible to Internal inspection tools Pressure testing Hydrostatic spike tests Excavation and in situ direct examination Guided wave ultrasonic testing Direct assessment Other technology

29 Non-Integrity Mangement Areas Assessment Additional requirements are provided for pipelines operating at MAOP < 30 percent of SMYS for external and internal corrosion on low-stress segments. Data analysis conducted by qualified individual in knowledge, training and experience Operator must consider uncertainties Operator must make determination within 180 days Remediation must be done in accordance with updated repair criteria timelines Operator must consider all available information

30 Immediate Two-year Conditions Monitoring Remaining strength of pipe is 1.1x MAOP Dent with indications of metal loss, cracking or stress riser Metal loss > 80% of wall Indication of metal-loss affecting longitudinal seam if seam formed by certain methods Any indication of: SCC SSWC Anomaly in the judgment of the operator that requires immediate action Smooth dent located between 8 and 4 o clock positions with depth > 6% of diameter Dent with > 2% of the pipeline diameter that impacts curvature at girth weld Remaining strength of pipe is predicted FPR at anomaly 1.25x, 1.39x, 1.67x and 2x for Class locations 1, 2, 3, and 4, respectively Metal loss > 50% of wall Predicted metal loss > 50% of wall at crossing of another pipeline or is in area with widespread circumferential corrosion Gouge or groove > 12.5% of wall Any indication of crack or crack-like defect other than immediate condition Dent with depth > 6% of pipeline diameter between 4 and 8 o clock position Dent with depth > 6 % of pipeline diameter between 8 and 4 o clock position with engineering analyses of dent demonstrate critical strain levels

31 Integrity Management (i) Pipe diameter, wall thickness, grade, seam type and joint factor (ii) Manufacturer and manufacturing date (iii) Material (iv) Equipment properties (v) Year of installation (vi) Bending methods (vii) Joining method, including process and inspection results (viii) Depth of cover surveys (ix) Crossings, casings (including if shorted), and locations of foreign line crossings and nearby high voltage power lines (x) Hydrostatic or other pressure test history (xi) Pipe coating methods (xii) Soil, backfill; (xiii) Construction inspection reports, including: (A) Girth weld nondestructive examinations; (B) Post backfill coating surveys (C) Coating inspection ( jeeping ) reports (xiv) Cathodic protection Data Integration installed, (xv) Coating type (xvi) Gas quality (xvii) Flow rate;(xviii) Normal maximum and minimum operating pressures, including MAOP (xix) Class location (xx) Leak and failure history (xxi) Coating condition; (xxii) CP system performance (xxiii) Pipe wall temperature (xxiv) Pipe operational and maintenance inspection reports, including but not limited to: (A) Data gathered through integrity assessments required under this part (B) Close interval survey (CIS) and electrical survey results; (C) Cathodic protection (CP) rectifier readings (D) CP test point survey readings and locations (E) AC/DC and foreign structure interference surveys (F) Pipe coating surveys, including surveys to detect coating damage, disbonded coatings, or other conditions that compromise the effectiveness of corrosion protection (G) Results of examinations of exposed portions of buried pipelines (H) Stress corrosion cracking (SCC) excavations and findings (I) Selective seam weld corrosion (SSWC) excavations and findings (J) Gas stream sampling and internal corrosion monitoring results (xxv) Outer Diameter/Inner Diameter corrosion monitoring (xxvi) Operating pressure history and pressure fluctuations

32 Integrity Management Data Integration Cont. (xxvii) Performance of regulators, relief valves, pressure control devices, or any other device to control or limit operating pressure to less than MAOP (xxviii) Encroachments and right-of- way activity (xxix) Repairs (xxx) Vandalism (xxxi) External forces (xxxii) Audits and reviews (xxxiii) Industry experience for incident, leak and failure history (xxxiv) Aerial photography (xxxv) Exposure to natural forces in the area of the pipeline, including seismicity, geology, and soil stability of the area; and (xxxvi) Other pertinent information derived from operations and maintenance activities and any additional tests, inspections, surveys, patrols, or monitoring required under this part.

33 Integrity Management Risk Assessment Analyze impact of potential failure on HCA Analyze the likelihood of for each individual threat or risk factor, and each unique combination of threats or risk factors that interact or simultaneously contribute to risk at a common location; Understand the nature of the threats, the failure mechanisms, the effectiveness of currently deployed risk mitigation activities, and how to prevent, mitigate, or reduce those risks; Account for, and compensate for, uncertainties in the model and the data used in the risk assessment; and Evaluate the potential risk reduction associated with candidate risk reduction activities such as preventive and mitigative measures and reduced anomaly remediation and assessment intervals.

34 Integrity Management Program Components Specific requirements for collecting, validating and integrating data models Process for selecting and use of direct assessment methods Monitoring gas quality

35 Integrity Management Program Components Expand on current baseline assessment methodology Strengthen requirements for assessment method Clarify selection and conduct of ILI per new mandatory reference to NACE, API, and ASME standards Expand requirements for ICDA and SCCDA Repair criteria aligned with those of MCA Clarify consideration of uncertainties in ILI reported results

36 Integrity Management Program Components Clarify requirement to apply knowledge gained through IM Clarify expectation that operators use knowledge from risk assessments to establish and implement adequate Preventive & Mitigative (P&M) measures Provide more explicit examples of the type of P&M measures to be evaluated Clarify requirements for validating & integrating pipeline data Clarify that data be verified and validated Clarify requirements for integrated analysis of data & information Establish minimum pipeline attributes that must be included

37 Integrity Management Program Components Strengthen corrosion control requirements Specific P&M measures for HCAs to address both external and internal corrosion Above ground surveys Close interval surveys Electrical interference surveys Add requirements for selecting P&M measures in HCAs to address internal corrosion and external corrosion Enhance internal & external corrosion control programs in HCAs to provide additional protection from corrosion commensurate with alternative MAOP pipelines

38 Integrity Management Program Components Management of change Codify the specific attributes of the Management of Change process from ASME/ANSI B31.8S, Section 11 (already incorporated by reference). Require operators to develop and follow a Management of Change process and address risk as part of the general requirements of Part 192.

39 Additional Provisions Requires pipeline inspection following extreme external events Incorporates provisions to address seismicity Adds requirement for safety features on launchers and receivers

40 What are your thoughts?

41 Natural Gas Transmission & Gathering Rulemaking General Thoughts Incredibly complicated, ambiguous Moves from performance to prescriptive Dilution of efforts to activities that do not target highest risk Incredibly costly Disruptive to communities, supply and power generation Specific data still needed to drive actual risk-based regulation

42 Next Steps & Timing Technical Advisory Committee Meeting - December 7 & 8, 2016 Clarify what requirements of the proposed rule are applicable to gathering and distribution lines General Topics MAOP Exceedance Reporting Accounting for Seismicity Safety of Launchers and Receivers Continual Surveillance after Weather Events Management of Change Reassessment Intervals Anomaly Response Criteria Preventative and Mitigative Measures Corrosion Topics Changes to Subpart I Internal and External P&M Measures IVP Topic Introduction

43 Next Steps & Timing Technical Advisory Committee Meeting #2 January 2017 Moderate Consequence Areas Expansion of in-line inspection Address concepts that appear throughout IVP Able to Accommodate Inspection by an ILI Use of Direct Assessment Requirement of No Objection Letters MAOP Verification Applicable Pipelines Pressure Testing, excluding use of spike testing Engineering Critical Assessment requirements

44 Next Steps & Timing Technical Advisory Committee Meeting #3 February 2017 Records Definition of TVC New Prospective Recordkeeping Requirements. Material Verification Required Data Elements Requirements for Opportunistic Collection Definitions: Definition of Gathering Line Transmission Line & Distribution Center Expansion of Integrity Management Beyond HCAs. Risk Assessments Hold for additional issues that need to be revisited

45 Hazardous Liquids Rule Docket number: PHMSA Significant: Yes Advanced notice: October 18, 2010 Proposed: October 13, 2015 Finalized: Pending Anticipated: End of year 2016 Commenters: 73

46 Onshore Hazardous Liquids Rulemaking Proposal: Extend reporting requirements to all gravity lines Technical Advisory Actions: Modified reporting Commitment that mapping would be required, but it would not be integrated into the NPMS Exemption for lines within facilities 1-year implementation schedule for annual reports 6-month implementation for accident reporting

47 Onshore Hazardous Liquids Rulemaking Proposal: Extend reporting requirements to all hazardous liquid gathering lines Technical Advisory Actions: Modified (abbreviated) reporting 1-year implementation schedule for annual reports 6-month implementation for accident reporting

48 Onshore Hazardous Liquids Rulemaking Proposal: Expand the use of leak detection systems for all hazardous liquid pipelines Technical Advisory Actions: Implementation period of five (5) years for existing pipelines Implementation period of one (1) year for new pipelines Clarify that this provision will not apply to offshore gathering lines

49 Onshore Hazardous Liquids Rulemaking Proposal: Clarify other requirements including: Requiring integration of pipeline information Periodic verification of the identification of HCAs Periodic verification of segment Technical Advisory Actions: Phase in over three (3) years - begin in one (1) year and all 21 attributes to be completed in three years.

50 Proposal: Require inspections of pipelines in areas affected by extreme weather, natural disasters, and other similar events within 72 hours Technical Advisory: Amended language to: Onshore Hazardous Liquids Rulemaking Apply to situations with a likelihood of damage Inspection to detect conditions that could adversely affect the safe operations Time begins from the point at which it becomes safe to access

51 Onshore Hazardous Liquids Rulemaking Proposal: Modify the IM repair criteria and apply those same criteria to any pipeline where the operator has identified repair conditions Technical Advisory Actions: Immediate repair conditions: Include crack criteria anomalies greater than 70 percent of wall thickness or the tool s maximum measurable depth if it is less than 70 percent

52 Onshore Hazardous Liquids Rulemaking Remove specific references to any indication of SCC and SSWC Allow for an industry recognized engineering analysis to determine those dents that are noninjurious and to further investigate if needed; and Instead of addressing cracks and SSWC specifically, expand the various accepted failure models that identify an anomaly that does not have the remaining strength to exceed 1.1 times the maximum operating pressure at the location of the anomaly, which should also include injurious cracks and SSWC.

53 Onshore Hazardous Liquids Rulemaking 270 day for HCA and 18 month for non-hca conditions: Revise the existing reference to cracks and include crack anomalies greater than 50 percent of the wall thickness or the tool s maximum measurable depth if it is less than 50 percent Allow for an industry-recognized engineering analysis to determine those dents that are non-injurious and no further investigation is needed; and To address cracks and SSWC, expand the various accepted failure models that identify an anomaly that does not have the remaining strength to exceed 1.25 times the maximum operating pressure at the location of the anomaly.

54 Onshore Hazardous Liquids Rulemaking Repair Criteria - continued Add Scheduled" Condition Anomalies that do not meet the 270 and 18 month repair criteria but have the possibility to segment inspection are subject to predictive modeling of remaining strength; and Investigation will be made in the years prior to next inspection if the predictive burst pressure is less than 1.1 times the maximum operating pressure at the location of the anomaly. Voted to keep timeframes and conditions as proposed except for: MOP< 1.0 to P burst / MOP < 1.25 Proposed SCC/SSWC IVP language permit engineering analysis to determine that certain types of anomalies might be considered non-critical and not require immediate evaluation that would otherwise be classified as immediate

55 Onshore Hazardous Liquids Rulemaking Proposal: Require all pipelines subject to IM to be capable of accommodation of in-line inspection tools within 20 years if affecting an HCA Technical Advisory Actions: Provided exemption from requirement if operator determines it would abandon or shut-down a pipeline as a result of the cost to comply with the requirement of this section.

56 Onshore Hazardous Liquids Rulemaking Proposal: Require periodic assessments of pipelines that are not already covered under the IM program requirements Technical Advisory Actions: Clarify applicability to Align requirements with that of existing IM requirements, but update to address tool selection and cracking

57 Onshore Hazardous Liquids Rulemaking Other provisions: Definition of HL pipes to capture biofuels Finish smart pig runs and outcomes within 180 days Take into account tool tolerance when doing ILI

58 Miscellaneous II Docket number: PHMSA Significant: Yes Proposed: July 10, 2015 Anticipated: End of 2016 Commenters: 39

59 Miscellaneous II Rulemaking Proposal: Expansion of OQ Elimination of 4-part test New construction Emergency response Knowledge, skill, ability Scope to: Gathering Effectiveness component

60 Immediate notice of incidents Control room management - team training Process to evaluate confidentiality of certain information Cost recovery Large projects New technologies Farm taps Miscellaneous II Rulemaking

61 Miscellaneous II Rulemaking Industry Concerns: Protection of information considered to be SSI or related to economic competitiveness Terms of requirement to pay for new technology review and Master Cost Recovery Agreement Difference between special permit and waiver use Definition of discovery Inconsistencies between preamble and proposed rule language Overhaul of operator qualification provisions Cost benefit analysis

62 Miscellaneous II Rulemaking Technical Advisory Actions Revise definition of confirmed discovery as confirmed discovery when it can be reasonably determined based on information available to the operator at the time that a reportable event has occurred even if only based on a preliminary evaluation. New and novel technologies means any products, designs, materials, testing, construction, inspection or operational procedures that are not addressed in 49 CFR Parts 192, 193 or 195 due to technology or design advances and innovations for new construction. Technologies that are addressed in consensus standards that are incorporated by reference into Parts 192, 193 and 195 are not new or novel technologies. In Section the phrases permitting activities, purchasing and right of way acquisition are deleted.

63 Miscellaneous II Rulemaking Technical Advisory Actions - Operator Qualifications (b) For the purpose of this subpart, a covered task is an activity identified by the operator that (1) is performed on a pipeline facility; (2) is an operations or maintenance task, including those conducted during an emergency response, or is a construction task or integrity management task; (3) is performed as a requirement of this part; (4) affects the operation or integrity of the pipeline and (5) design and engineering tasks performed off the pipeline facility are not included.

64 Miscellaneous II Rulemaking Technical Advisory - Operator Qualifications (b)(10) is revised to read as follows: "Provide supplemental training for the individual when significant changes are made to procedures and specifications impacting the performance of a covered task. Special Permit In (d)(1), the mandatory language is revised by replacing the word application with the phrase application or renewal; Revise (f) to limit aerial photography of pipeline segments where special permits affect public safety, such as a class location special permit that allows a less stringent design factor in a populated area and allows operators to submit a summary of inline inspection survey results with permit renewals; Revise (e) to clarify that special permit renewals must be submitted 180 days prior to the grant expiration.

65 Technical Advisory - Confidential Information Miscellaneous II Rulemaking Recommended revisions to Section clarify the regulatory text to state that the criteria under FOIA will be used, and also to reference DOT's FOIA regulations, which currently set out the process for how you handle when records are marked confidential. That includes a consultation process. Note: The intent of this particular provision was to set up a process for protecting confidential commercial information. It was not intended to address security. Security is a completely different subject and a different decision making process.

66 Miscellaneous II Rulemaking Recommended revision to Section (b) "As soon as possible, but not later than 32 hours after an accident, an operator must drug test each surviving covered employee whose performance of a covered function either contributed to the accident or cannot be completely discounted as a contributing factor to the accident. An operator may decide not to test under this paragraph, but such a decision must be based on specific information that the covered employee's performance had no role in the cause or severity of the accident. Deleted: "Or because of the time between the performance of the accident, it is not likely that a drug test would reveal whether the performance was affected by drug use."

67 NPMS Docket number: PHMSA Significant: Not applicable Request for comments: July 30, 2014 Request for comments: August 27, 2015 Request for comments: July 22, 2016 Anticipated: Winter 2016/2017 Commenters: 55

68 NPMS Goals: Promote public awareness with emergency responders and local officials More effective emergency response Strengthen PHMSA s ability to evaluate regulations Better support research and development - helping to predict the impact of new technology Assist with risk ranking of pipelines and audit priorities

69 NPMS Gas transmission operators: +/- 50 feet accuracy for all segments which are in: a Class 2, Class 3, or Class 4 area; are within an HCA or have one or more buildings intended for human occupancy an identified site a right of way for a designated interstate; freeway, expressway, or other principal 4-lane arterial All other gas pipeline segments must be mapped to a positional accuracy of +/- 100 feet. Hazardous liquid pipeline operators are required to submit data at +/- 50 feet accuracy

70 NPMS Public information: Centerlines with new accuracy standard Pipe material Pipe joining method Onshore/offshore Abandoned lines Breakout tanks

71 NPMS Information restricted to registered users: Diameter Commodity detail Class location Pipe grade Seam type Predominant decade of installation Wall thickness Year of last ILI inspections (by assessment methodology)

72 NPMS Inline inspection Gas HCA segment Coated/uncoated Cathodically protected (Y/N) FRP control and sequence numbers Pump and compressor stations Gas storage fields (by type) New LNG plant attributes

73 NPMS Security sensitive information: Highest percent operating SMYS (by range) MAOP/MOP Segment could affect an HCA Mainline block valves

74 NPMS Industry concerns: Process by which changes are occurring Timing Overall burden and cost Sensitive information Back-door integrity verification Ability to navigate the system

75 Plastic Pipe Rulemaking Docket number: PHMSA and 0098 Significant: No Proposed: May 21, 2015 Anticipated: End of 2016 Commenters: 43

76 Plastic Pipe Rulemaking Proposal: Traceability and Tracking Add definitions for traceability information and tracking information Require operators to adopt the tracking and traceability requirements in ASTM F a, Standard Specification for Tracking and Traceability Encoding System of Natural Gas Distribution Components (Pipe, Tubing, Fittings, Valves, and Appurtenances) Design Factor for Polyethylene (PE) Increase the design factor for PE pipe from 0.32 to 0.40 in

77 Plastic Pipe Rulemaking Proposal: Expanded Use of Polyamide-11 (PA-11) Allow PA 11 pipe (PA32316) for pressures up to 250 psi, diameters up to 6 inches, and additional limitations on wall thickness as listed in the petition Incorporation of PA-12 Risers Same as PA-11 Add the requirements for the design ( ) and construction of risers ( (j) and (a)(2)) associated with plastic pipe

78 Plastic Pipe Rulemaking Fittings Require mechanical fittings or joints that are designed and tested to provide a seal plus resistance to lateral forces so that a large force on the connection would cause the pipe to yield before the joint does Require such fittings used within plastic pipelines be cathodically protected and monitored in accordance with and (a)

79 Plastic Pipe Rulemaking Repairs Include a requirement for all plastic pipe and or components to be replaced if they have a scratch or gouge exceeding 10 percent of the wall thickness Incorporate a new section ( ) to prohibit the use of leak-repair clamps as a means for permanent repair on gas pipe used in distribution service

80 Plastic Pipe Rulemaking Industry concerns: Tracking and traceability Applicability of LDC standards to transmission and gathering Definition of weak link Ensuring the location of facilities under relating to trenchless excavation Maximum bend radius Calibration used for joining plastic pipe Requirement to use mechanical fittings, joints and connections required to be Category 1

81 Plastic Pipe Rulemaking Technical Advisory Meeting Outcomes Consider the later standard ASTM-D , and PHMSA research the retroactivity of the design factor for PE with a.40 design factor. PHMSA clarifies that these provisions are not retroactive, and incorporate PHMSA 21 recommendations. Revise Paragraph G as follows: G, electrically isolated metal alloy fittings in plastic pipelines under this section not meeting the criteria contained in Paragraph F must be cathodically protected and maintained in accordance with the operator's integrity management plan.

82 Plastic Pipe Rulemaking Extend compliance deadline from two to five (2 to 5) years and make trackability only applicable at time of instillation. Trenchless excavation expectations to maintain clearance

83 Automatic Valve and Rupture Detection Rule Docket number: PHMSA Significant: Yes Anticipated: July 2017

84 Goals: Automatic Valve and Rupture Detection Rule Performance driven to: Improve mitigation and response times Shorten isolation times Address: Congressional mandates Incorporate NTSB and GAO recommendations

85 Proposals likely to include: Automatic Valve and Rupture Detection Rule Mandatory installation of automatic shutoff valves (ASVs), remote controlled valves (RCVs), or equivalent technology Establish performance-based meaningful metrics of rupture detection for gas and liquid transmission Locations: High Consequence Areas (HCA) for Hazardous Liquid and HCA, Class 3 and 4 for Natural Gas

86 Underground Storage Docket number: PHMSA Significant: Yes Anticipated: Emergency Order expected December 2016 Permanent rule expected late 2017

87 Underground Storage Depleted Fields, Aquifers and Salt Caverns Incidents Aging Facilities Public Concern API 1170 & API 1171 October 19-20, 2016 Research Forum Phoenix, Arizona

88 Additional Rulemakings Carbon Dioxide Transported in Gaseous State IMP expansion and class location replacement Data collection Excess flow valves

89 NTSB 17 remaining issues Accidents driving recommendations not covered by pending rules Eliminating discretion and grandfather clause Post construction hydro-test Meaningful metrics Team training

90 Pipeline Safety Reauthorization Act (S. 2276) Directs adoption of new rules for: Underground natural gas storage Small scale LNG facilities Expansion of technical advisory committee 30-day post inspection report Joint state/federal oversight Great Lakes designation as HCA Coordination with FERC during pre-filing procedures

91 Pipeline Safety Reauthorization Act (S. 2276) Periodic updates on rule development Rescind letter regarding placecards on flammable hazardous materials to represent the lowest flash point Prioritize development of each outstanding statutory requirements Exclusions from response plans including: propriety information, security-sensitive information, specific response resources, tactical resource deployment plans and specific amounts and locations of worst case discharge Withholding of state funding if the state authority is not maintaining a satisfactory effort to carry out a safety program or failing to act satisfactorily as an agent

92 Reauthorization (S. 2276) Studies: Natural gas and hazardous liquid integrity management Natural gas leak reporting Odorization study Damage prevention technology Staffing of PHMSA Nationwide integrated pipeline safety database Review of TSA pipeline security program Aliso Canyon Gas Task Force R & D programs that encourage joint ventures State by state reviews of repair and replacement of LDCs and barriers to address leaking pipelines

93 Contact Information Jennifer Bremer Sander Resources P: C: