1. The Gas “Mega Rule” Western Regional Gas Conference Tempe AZ August 23, 2016 JOHN A. JACOBI, P.E., J.D.

2. Outline 2 A.The Rulemaking Process B.History of the Gas “Mega Rule” C.The Gas Mega Rule Things that are not to be changed (Valve spacing, underground storage, risk models, NPMS reporting, etc.)

3. Outline 3 C.The Gas Mega Rule (continued) Gathering Lines (newly regulated gathering and new reporting requirements) The “Grandfather” clause Moderate Consequence Areas Other Definitions (some proposed and some that should have been proposed)

4. Outline 4 C.The Gas Mega Rule (continued) §192.624 – MAOP Verification Subpart O Gas Transmission Pipeline Integrity Management §192.607 Verification of Pipeline Material §192.619 MAOP §192.710 Pipeline Assessments

5. Outline 5 C.The Gas Mega Rule (continued) Miscellaneous Provisions −§192.478 Internal Corrosion −§192.493 ILI Standards −§192.506 Spike Tests −§192.613(c) Weather Events Overview

6. The Rulemaking Process 6 Source of Authority Advanced Notice of Proposed Rulemaking Notice of Proposed Rulemaking Economic Impact Public Comments Timing

7. History 7 76 FR 53086 et. seq.; August 15, 2011; Docket No. PHMSA-2011-0023 Response to CY2010 incidents, then upcoming reauthorization, and follow up to liquid ANPRM Comment period closed January 20, 2012 NOPR 81 FR 20722 et. seq., April 8, 2016 Public Comment Period closed July 8, 2016

8. Docket PHMSA-2011-0023 8 Go to www.regulations.gov enter the docket number All of the public records will be there!!

9. Abstract 9 In this rulemaking, PHMSA will be revisiting the requirements in the Pipeline Safety Regulations addressing integrity management principles for Gas Transmission pipelines. In particular, PHMSA will address: repair criteria for both HCA and non-HCA areas, assessment methods, validating & integrating pipeline data, risk assessments, knowledge gained through the IM program, corrosion control, management of change, gathering lines, and safety features on launchers and receivers.

10. Cost Benefit 10 Summary of Average Annual Present Value Benefits and Costs 1 (Millions; 2015$) Topic Area 7% Discount Rate 3% Discount Rate BenefitsCostsBenefitsCosts Re-establish MAOP, verify material properties, and integrity assessments outside HCAs $196.9 -$230.5$17.8 $247.8 -$288.6$22.0 Integrity management process clarifications n.e.$2.2 n.e.$1.3 Management of change process improvement $1.1$0.7 $1.2$0.8 Corrosion control $5.5$6.3 $5.9$7.9 Pipeline inspection following extreme events $0.3$0.1 $0.3$0.1 MAOP exceedance reports and records verification n.e.$0.2 n.e.$0.2 Launcher/receiver pressure relief $0.4$0.0 $0.6$0.0 Gas gathering regulations $11.3$12.6 $14.2$15.1 Total $215.6 -$249.2$39.8 $270 -$310.8$47.4 HCA = high consequence area MAOP = maximum allowable operating pressure n.e. = not estimated 1. Total over 15-year study period divided by 15. Additional costs to states estimated not to exceed $1.5 million per year. Range of benefits reflects range in estimated defect failure rates. 2. Break even value of benefits, based on the average consequences for incidents in high consequence areas, would equate to less than one incident averted over the 15-year study period.

11. Estimated Per-Mile Costs 11 PHMSA has data on gas transmission pipeline operators affected by the proposed rule. However, PHMSA does not have data on currently unregulated gas gathering pipeline operators. Therefore, this [Initial Regulatory Flexibility Analysis] document provides the elements of an IFRA, including PHMSA’s analysis of the potential impact of the proposed Safety of Gas Transmission and Gathering Pipelines rule on small entities.

12. Estimated Per-Mile Costs 12 Table 3. Estimated Per-Mile Costs for Topic Area 1 by Subtopic Sub-Topic Approximate Equivalent Mileage Mileage 1 Total Ongoing Costs 2 Cost Per Mile 3 Approximate Cost per Mile per Year 4 Re-establish MAOP: HCA > 30% SMYS HCA Miles 19,872$33,225,784$1,672$111 Re-establish MAOP: Inadequate Records Mileage reported with incomplete MAOP records 4,363 $213,837,287 $49,012 $3,267 Integrity Assessment: Non- HCA Non-HCA 281,901$142,673,072$506$34 Re-establish MAOP: HCA 20-30% SMYS; Non-HCA Class 3 and 4; Non-HCA Class 1 and 2 piggable All GT Miles 301,774 $67,931,862 $225 $15 GT = gas transmission HCA = high consequence area MAOP = maximum allowable operating pressure SMYS = specified minimum yield strength 1.Source: 2014 Gas Transmission Annual Reports 2.See the Regulatory Impact Analysis in the docket for the rulemaking. 3.Calculated as total cost divided by applicable mileage. 4.Calculated as per mile cost divided by 15 years.

13. Things that will not change 13 A.Class Locations will not go away – yet B.Data – Reliable, Traceable, Verifiable & Complete mentioned 30 times!! C.Risk Models – the thrust is risk-based but no new models are proposed D.Valve Spacing – not changed

14. Things that will not change 14 E.Underground storage – will be a separate rulemaking F.NPMS Reporting – not changed in terms of what has to be reported G.Management of Change – no significant changes H.Quality Management Systems – will morph into a separate rulemaking for Pipeline Safety Management (PSM – API RP 1173)

15. Documentation 15 The phrase “reliable, traceable, verifiable, and complete” appears 30 times in the NOPR. Nowhere in the NOPR (or in the current Part 192) are any of these words defined. PHMSA should provide a reasonable definition of these words.

16. Documentation 16 The phrase “for the life of the pipeline” appears 19 times in the body of the NOPR. A new Appendix A to Part 192 is titled “Records Retention Schedule for Transmission Pipelines.” Over 80 code sections or subsections are listed in the proposed Appendix A. The overwhelming majority are “for the life of the pipeline.”

17. §192.13 General Requirements 17 New §192.13(e): Keep records for the retention period specified in (new) Appendix A Records must be reliable, traceable, verifiable, and complete No or inadequate records – must develop using (new) §192.607

18. §192.67 Records: Materials 18 New Operators of transmission pipelines must acquire and retain for the life of the pipeline the original steel pipe manufacturing records that document tests, inspections, and attributes required by the manufacturing specification in effect at the time the pipe was manufactured, including, but not limited to, yield strength, ultimate tensile strength, and chemical composition of materials for pipe in accordance with §192.55.

19. §192.205 Records: Components 19 New (transmission lines) Must acquire and retain records documenting the mfg. std. and pressure rating to which each valve was mfg. and tested. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of X42 or greater must have records documenting the mfg. spec. in effect at the time of mfg, including, but not limited to, yield strength, ultimate tensile strength, and chemical composition of materials.

20. Reporting (Part 191) 20 Reporting of incidents, safety-related conditions, exceedances of MAOP, annual pipeline summary data, and National Operator Registry information Would apply to offshore gathering lines and to onshore gathering lines, whether designated as “regulated onshore gathering lines” or not (as determined in § 192.8).

21. Reporting (Part 191) 21 Distribution & gathering lines expressly required to report safety related conditions related to exceeding MAOP (§191.23) §191.25(b) Each report of a MAOP exceedance meeting the requirements of criteria in § 191.23(a)(9) for a gas transmission pipeline must be reported within five calendar days of the exceedance using the reporting methods and report requirements described in §191.25(c).

22. Documentation 22 PHMSA is serious about requiring good solid records regarding compliance!

23. §192.8 Gas Gathering 23 Type A gathering lines 8 inches or greater in diameter in Class 1 locations may be regulated. Requirements would include damage prevention, corrosion control (for metallic pipe), public education program, maximum allowable operating pressure limits, line markers, and emergency planning (same as for Type B gathering in Class 3 and 4 locations). HINT: It is likely that the diameter will be increased.

24. §192.9 Gas Gathering 24 New §192.9(f): If a change in class location or increase in dwelling density causes an onshore gathering line to be a regulated onshore gathering line, the operator has one year for Type A, Area 2 and Type B lines and two years for Type A, Area 1 lines after the line becomes a regulated onshore gathering line to comply with this section.

25. New §192.3 Gathering Definition 25 Gathering Lines (Onshore) will be pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of a number of endpoints. Incidental gathering would still be recognized but limited.

26. Other Gathering Definitions 26 API RP 80 “Guidelines for the Definition of Onshore Gas Gathering Lines” would no longer be incorporated by reference. New §192.3 gathering related definitions (consistent with RP 80 definitions): Gas Processing Plant Gas treatment facility Onshore Production facility/operation

27. The “Grandfather Clause” 27 Any segment for which MAOP was established in accordance with §192.619(c) prior to the effective date of the new rule will have to have its pressure verified under §192.624. Applicability Onshore transmission lines in §192.903 HCAs, or in Class 3 or Class 4 Locations or in a Moderate Consequence Areas (if the line is piggable in the MCA)

28. Moderate Consequence Area 28 Moderate Consequence Area (MCA, §192.3) 5 or more buildings intended for human occupancy within PIR; or An occupied site within PIR; or a right-of-way for a designated interstate, freeway, expressway, and other principal 4-lane arterial roadway within PIR; and does not meet the definition of a §192.903 high consequence area.

29. Occupied Site 29 An outside area or open structure that is occupied by 5 or more persons on at least 50 days in any 12-month period A building that is occupied by 5 or more persons on at least 5 days a week for 10 weeks in any 12- month period

30. Other Definitions (§192.3) 30 Transmission line definition essentially unchanged Distribution line (Onshore) definition unchanged MISSING: Definition of “in-plant piping” and meaningful definitions of distribution line and distribution system.

31. Other Definitions (§192.3) 31 Distribution Center Dry gas or dry natural gas In-line inspection (ILI) In-line inspection tool or instrumented internal inspection device Legacy construction techniques Legacy pipe Modern pipe Significant Seam Cracking Significant Stress Corrosion Cracking Wrinkle bend

32. § 192.5 Class locations 32 Definitions unchanged but: Records for transmission pipelines documenting class locations and demonstrating how an operator determined class locations in accordance with this section must be retained for the life of the pipeline.

33. § 192.7 - New Standards 33 API STD 1163-2005, “In-Line Inspection Systems Qualification Standard” (§192.493) NACE Standard Practice 0102-2010, "Inline Inspection of Pipelines“ (§§192.150(a) and 192.493) NACE Standard Practice 0204-2008, "Stress Corrosion Cracking Direct Assessment” (§§ 192.923(b)(3) and 192.929)

34. § 192.7 - New Standards 34 NACE Standard Practice 0206-2006, "Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas" (§§ 192.923(b)(2); 192.927(b); and192.927(c)) ANSI/ANST ILI-PQ-2010, "In-line Inspection Personnel Qualification and Certification” (§192.493)

35. § 192.7 - New Standards 35 Battelle's Experience with ERW and Flash Welding Seam Failures: Causes and Implications (Task 1.4)” (§192.624(c) and (d)) Battelle Memorial Institute, "Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams" (Subtask 2.4)” (§192.624(c) and (d))

36. § 192.7 - New Standards 36 Battelle Final Report No. 13-021, "Predicting Times to Failures for ERW Seam Defects that Grow by Pressure Cycle Induced Fatigue (Subtask 2.5)” (§192.624(c) and (d)) Battelle Memorial Institute, "Final Summary Report and recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures -- Phase 1 (Task 4.5)” (§192.624(c) and (d))

37. §192.13 General Requirements 37 New §192.13(d): Operators must evaluate and mitigate, as necessary, risks to the public and environment as an integral part of managing pipeline design, construction, operation, maintenance, and integrity, including management of change (MOC). MOC = ASME/ANSI B31.8S, section 11 8 required elements for MOC

38. §192.624 Establishing MAOP 38 This section is potentially the most costly. It is certainly the longest and most complex!! General Applicability Onshore transmission lines in §192.903 HCAs, or in Class 3 or Class 4 Locations or in a Moderate Consequence Areas (if the line is piggable in the MCA)

39. §192.624 Applicability 39 Other Criteria Any segment that has experienced a reportable in-service incident, as defined in §191.3, since its most recent successful Subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking.

40. §192.624 Applicability 40 Other Criteria Any segment for which pressure test records necessary to establish maximum allowable operating pressure per Subpart J for the pipeline segment, including, but not limited to, records required by § 192.517(a), are not reliable, traceable, verifiable, and complete. Note: This particular requirement does NOT apply in Moderate Consequence Areas.

41. §192.624 Applicability 41 Other Criteria Any segment for which MAOP was established in accordance with §192.619(c) prior to the effective date of the new rule. Note: §192.619(c) is the “Grandfather Clause.” This requirement eliminates the “Grandfather Clause.” Any operator with grandfathered pipe will have work to do!!

42. §192.624 Deadlines 42 Plans must be developed and documented within 1 year of the effective date. Plan must be implemented for at least 50% of the mileage within 8 years of effective date. Plan must be implemented for 100% of the mileage within 15 years of effective date. May petition for one year extension of deadlines (lots of strings attached)

43. §192.624 Acceptable Methods 43 Method 1 – Pressure Test Method 2 – Pressure Reduction (HAOP) Method 3 – Engineering Critical Assessment Method 4 – Pipe Replacement Method 5 – Pressure Reduction (Small Dia & PIR) Method 6 – Alternative Technology

44. Subpart O – Integrity Mgm’t 44 Incredibly complex Allegedly would apply only to transmission lines in HCAs (PIR containing ≥ 20 buildings intended for human occupancy or an identified site) Data gathering and integration would apply to both covered segments and non-covered segments and extremely prescriptive.

45. Subject Matter Experts (SMEs) 45 If input is obtained from subject matter experts, the operator must employ measures to adequately correct any bias in SME input. Bias control measures may include training of SMEs and use of outside technical experts (independent expert reviews) to assess quality of processes and the judgment of SMEs. Operator must document the names of all SMEs and information submitted by the SMEs for the life of the pipeline. Apparently whoever wrote this is a cynic.

46. Spatial Relationships 46 Must identify and analyze spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings; evidence of pipeline damage where overhead imaging shows evidence of encroachment). Storing or recording the information in a common location, including a geographic information system (GIS), alone, is not sufficient.

47. Plastic Transmission Pipeline 47 Must assess the threats using the information in sections 4 and 5 of ASME B31.8S, and consider any threats unique to the integrity of plastic pipe such as poor joint fusion practices, pipe with poor slow crack growth (SCG) resistance, brittle pipe, circumferential cracking, hydrocarbon softening of the pipe, internal and external loads, longitudinal or lateral loads, proximity to elevated heat sources, and point loading.

48. Cyclic Fatigue 48 Fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis must be conducted in accordance with (new) §192.624(d) for cracks. Cyclic fatigue analysis must be annual, not to exceed 15 months.

49. Miscellaneous Provisions 49 §192.478 Internal Corrosion §192.493 ILI Standards §192.506 Spike Tests §192.613(c) Weather Events

50. §192.478 Internal Corrosion 50 Entire section added to require gas analysis for potentially corrosive constituents (such as carbon dioxide, hydrogen sulfide, sulfur, microbes, and free water, either by itself or in combination). Coupons and monitoring would be required if potentially corrosive constituents present.

51. §192.493 ILI 51 Part 192 ILI must comply with API STD 1163, In- line Inspection Systems Qualification Standard; ANSI/ASNT ILI-PQ-2005, In-line Inspection Personnel Qualification and Certification; and NACE SP0102-2010, In-line Inspection of Pipelines. Assessments may also be conducted using tethered or remotely controlled tools, not explicitly discussed in NACE SP0102-2010, provided they comply with those sections of NACE SP0102-2010 that are applicable.

52. §192.506 Spike Tests 52 30% SMYS or greater with integrity threats “that cannot be addressed by other means such as in-line inspection or direct assessment.” Must use water as test medium. Baseline test pressure (8 hours) must be §192.619, §192.620 or (new) §192.624 as applicable (w/o spike). Spike = lesser of 1.50 times MAOP or 105% SMYS for at least 30 minutes.

53. §192.506 Spike Tests 53 Spike test must be successfully completed w/in first 2 hours as part of 8 hour baseline test (i.e., spike counts as part of 8 hour test). If time dependent threat is present (e.g., cracking), a retest interval under new §192.624 must be established. Alternative Technology is possible with LOTS of technical support. (Good luck!)

54. §192.613(c) 54 After extreme weather events such as a hurricanes floods, earthquakes, landslides, natural disasters potentially affected onshore systems must be inspected. Must be based upon specific system & nature of potential damage Must commence within 72 hours of when need is identified OR when system can be safely accessed and equipment & personnel are available (whichever is sooner) (are they kidding??)

55. §192.613(c) 55 Remedial action to be determined by operator: (i) Reducing the operating pressure or shutting down the pipeline; (ii) Modifying, repairing, or replacing any damaged pipeline facilities; (iii) Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right of way; (iv) Performing additional patrols, surveys, tests, or inspections; (v) Implementing emergency response activities with Federal, State, or local personnel; or (vi) Notifying affected communities of the steps that can be taken to ensure public safety.

56. Overview 56 Documentation, Documentation, Documentation!! (materials, anomalies, compliance, etc., etc., etc.) Significantly more prescriptive than existing provisions Fracture Mechanics & Metallurgy More pipe covered (gathering & MCA) Schedule

57. Questions 57 John Jacobi john.jacobi@g2-is.com (713) 260-4039 (Office) (832) 712-3098 (Mobile) Thank YOU!!