Pipeline Safety: Safety of Hazardous Liquid Pipelines, 52260-52298 [2019-20458]

Download as PDF 52260 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 195 [Docket No. PHMSA–2010–0229; Amdt. No. 195–102] RIN 2137–AE66 Pipeline Safety: Safety of Hazardous Liquid Pipelines Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Final rule. jbell on DSK3GLQ082PROD with RULES3 AGENCY: SUMMARY: In response to congressional mandates, NTSB and GAO recommendations, lessons learned, and public input, PHMSA is amending the Pipeline Safety Regulations to improve the safety of pipelines transporting hazardous liquids. Specifically, PHMSA is extending reporting requirements to certain hazardous liquid gravity and rural gathering lines; requiring the inspection of pipelines in areas affected by extreme weather and natural disasters; requiring integrity assessments at least once every 10 years of onshore hazardous liquid pipeline segments located outside of high consequence areas and that are ‘‘piggable’’ (i.e., can accommodate inline inspection devices); extending the required use of leak detection systems beyond high consequence areas to all regulated, non-gathering hazardous liquid pipelines; and requiring that all pipelines in or affecting high consequence areas be capable of accommodating in-line inspection tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. Additionally, PHMSA is clarifying other regulations and is incorporating Sections 14 and 25 of the PIPES Act of 2016 to improve regulatory certainty and compliance. DATES: The effective date of this final rule is July 1, 2020. The incorporation by reference of certain publications listed in the rule was approved by the Director of the Federal Register as of March 24, 2017 and March 6, 2015. FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney, Project Manager, by telephone at 713– 272–2855. General information: Robert Jagger, Senior Transportation Specialist, by telephone at 202–366–4361. SUPPLEMENTARY INFORMATION: I. Executive Summary VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 A. Purpose of the Regulatory Action B. Summary of the Major Provisions of the Regulatory Action in Question C. Costs and Benefits II. Background A. Detailed Overview B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 C. National Transportation Safety Board Recommendations D. Summary of Each Topic III. Pipeline Advisory Committee IV. Analysis of Comments and PHMSA Response A. Reporting Requirements for Gravity Lines B. Reporting Requirements for Gathering Lines C. Pipelines Affected by Extreme Weather and Natural Disasters D. Periodic Assessment of Pipelines Not Subject to IM E. IM and Non-IM Repair Criteria F. Leak Detection Requirements G. Increased Use of ILI Tools in HCAs H. Clarifying Other Requirements V. PIPES Act of 2016 VI. Section-by-Section Analysis VII. Regulatory Notices I. Executive Summary A. Purpose of the Regulatory Action In recent years, there have been significant hazardous liquid pipeline accidents, most notably the 2010 crude oil spill near Marshall, MI, during which at least 843,000 gallons of crude oil were released, significantly affecting the Kalamazoo River. In response to accident investigation findings, incident report data and trends, and stakeholder input, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is amending the hazardous liquid pipeline safety regulations to improve protection of the public, property, and the environment by closing regulatory gaps where appropriate and ensuring that operators are increasing the detection and remediation of pipeline integrity threats, and mitigating the adverse effects of pipeline failures. On October 18, 2010, PHMSA published an Advanced Notice of Proposed Rulemaking (ANPRM) in the Federal Register (75 FR 63774). The ANPRM solicited stakeholder and public input and comments on several aspects of the hazardous liquid pipeline regulations being considered for revision or updating to address various pipeline safety issues. Subsequently, Congress enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112–90) (2011 Pipeline Safety Act). That legislation included several provisions that are relevant to the regulation of hazardous liquid pipelines. The 2011 Pipeline Safety Act included mandates for PHMSA to complete studies on PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 topics including existing Federal and State regulations for gathering lines, on automatic shutdown and remote control valves, expanding integrity management requirements beyond high-consequence areas, and on the leak detection systems used by hazardous liquid operators. PHMSA completed these studies and submitted the valve and leak detection studies to Congress on December 27, 2012; the gathering line study to Congress on May 8, 2015; and the integrity management (IM) study in April of 2016. These studies are available in the docket for this rulemaking. Shortly after the 2011 Pipeline Safety Act was passed, the National Transportation Safety Board (NTSB) issued its accident investigation report on the Marshall, MI, accident on July 10, 2012. In it, the NTSB made recommendations regarding the need to revise and update hazardous liquid pipeline regulations. Specifically, the NTSB issued recommendations P–12–03 and P–12–04, which addressed detection of pipeline cracks and ‘‘discovery of condition,’’ respectively. The ‘‘discovery of condition’’ recommendation would require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators notify PHMSA and provide an expected date when adequate information will become available. The Government Accounting Office (GAO) also issued a recommendation in 2012 concerning hazardous liquid and gas gathering pipelines. Recommendation GAO–12–388, dated March 22, 2012, states, ‘‘To enhance the safety of unregulated onshore hazardous liquid and gas gathering pipelines, the Secretary of Transportation should direct the PHMSA Administrator to collect data from operators of federally unregulated onshore hazardous liquid and gas gathering pipelines, subsequent to an analysis of the benefits and industry burdens associated with such data collection.’’ On October 13, 2015, PHMSA published a NPRM to seek public comments on proposed changes to the hazardous liquid pipeline safety regulations (80 FR 61609). A summary of those proposed changes is provided later in this document. Between the publication of the NPRM and this final rule, the President signed the ‘‘Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016’’ (PIPES Act of 2016), Public Law 114–183, on June 22, 2016. While the PIPES Act of 2016 contained several mandates that must be addressed E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations through rulemaking, certain provisions are self-executing standards that can be incorporated into this final rule rulemaking without a prior NPRM and opportunity to comment. Those changes are outlined in Section V of this document. B. Summary of the Major Provisions of the Regulatory Action In response to these mandates, recommendations, lessons learned, and public input, PHMSA is making certain amendments to the Pipeline Safety Regulations affecting hazardous liquid pipelines. The first and second amendments extend reporting requirements to certain hazardous liquid gravity and rural gathering lines not currently regulated by PHMSA. The collection of information about these lines, including those that are not currently regulated, is authorized under the Pipeline Safety Laws, and the resulting data will assist in determining whether the existing Federal and State regulations for these lines and the scope of their applicability are adequate. The third amendment requires inspections of pipelines in areas affected by extreme weather or natural disasters that could impose unexpected longitudinal or circumferential pipe loads, or other risks to the pipeline’s integrity and continued safe operation. This provision affects all covered lines under § 195.1, whether they be onshore or offshore, and in a high consequence area (HCA) or outside an HCA.1 Such inspections will help to ensure that operators can safely operate pipelines after these events. The fourth amendment requires integrity assessments at least once every 10 years, using inline inspection tools or other technology, as appropriate for the threat being assessed, of onshore, piggable, hazardous liquid pipeline segments located outside of HCAs. Existing regulations require operators to assess hazardous liquid pipeline segments located inside HCAs at least once every 5 years. These assessments will provide important information to operators about the condition of these pipelines, including the existence of internal and external corrosion and deformation anomalies. The fifth amendment extends the required use of leak detection systems beyond HCAs to all regulated hazardous liquid pipelines, except for offshore gathering and regulated rural gathering pipelines. The use of such systems will help to mitigate the effects of hazardous liquid pipeline failures that occur outside of HCAs. The sixth amendment requires that all pipelines in or affecting HCAs be capable of accommodating in-line inspection tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. In-line inspection tools are an effective means of assessing the integrity of a pipeline and broadening their use will improve the detection of anomalies and prevent or mitigate future accidents in high-risk areas. Finally, PHMSA is clarifying other 52261 regulations and is incorporating Sections 14 and 25 of the PIPES Act of 2016 to improve regulatory certainty and compliance. C. Cost and Benefits Consistent with Executive Orders 12866 and 13563, PHMSA has prepared an assessment of the benefits and costs of the rule as well as reasonably feasible alternatives. PHMSA estimates that up to 502 hazardous liquid operators may incur costs to comply with the NPRM. The estimated annual costs for individual components of the requirements in this rulemaking range between approximately $5,000 and $10.5 million, with aggregate costs of approximately $19.5 million to $21.4 million for all requirements.2 This final rule is primarily designed to mitigate or prevent hazardous liquid pipeline incidents, and is expected to reduce pipeline incident damages, including injuries and fatalities, cleanup and response costs, property damage, product loss, and ecosystem impacts. The rule’s information reporting requirements are designed to provide PHMSA information to inform regulatory decision-making. The Regulatory Impact Analysis (RIA) for this final rule is available in the docket. The table below provides a summary of the estimated costs and benefits for each of the eight major provisions and in total (see the RIA for the details of these estimates). ANNUALIZED COSTS AND BENEFITS BY REQUIREMENT AREA (2017$) 3 Annual costs 1 jbell on DSK3GLQ082PROD with RULES3 Final rule requirement area Benefits 3% discount rate 7% discount rate $5,000 ................... $75,000 ................. Minimal .................. $5,000 ................... $76,000 ................. Minimal .................. 1. Reporting requirements for gravity lines ........... 2. Reporting requirements for gathering lines ....... 3. Inspections of pipelines in areas affected by extreme weather events or natural disasters 4. 4. Assessments of onshore pipelines that are not already covered under the IM program using ILI every 10 years 5 6. 5. IM repair criteria 8 .............................................. 6. LDSs on pipelines located outside HCAs 6 ....... $6,467,000 ............ $6,467,000 ............ $0 .......................... $8,652,000 ............ $0 .......................... $10,508,000 .......... 7. Increased use of ILI tools 10 .............................. 8. Clarify certain IM plan requirements ................. Minimal .................. $4,269,000 ............ Minimal .................. $4,343,000 ............ Total ................................................................ $19,468,000 .......... $21,399,000 .......... Better risk understanding and management.2 Better risk understanding and management.3 Additional clarity and certainty for pipeline operators. Avoided incidents and damages through detection of safety conditions.7 $0. Reduced damages through earlier detection and response.9 Improved detection of pipeline flaws.10 Reduced damages through prevention and earlier detection and response.11 Reduced damages from avoiding and/or mitigating hazardous liquid releases. 1 Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in individual sections of the document. One-time costs are annualized over a 10-year period using discount rates of 3 percent and 7 percent. 2 Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of 101 gallons per year to generate benefits that equal the costs. 1 High Consequence Areas are defined in 49 CFR 195.450. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 2 Estimated costs are annualized using a 7 percent discount rate. PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 E:\FR\FM\01OCR3.SGM 01OCR3 52262 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations 3 The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of 1,493 gallons per year to generate benefits that equal the costs. 4 To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not reflected in this analysis. 5 PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios: (1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two scenarios are $0 and $12.9 million, respectively. 6 Excludes gathering lines. 7 Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to prevent 12 incidents for benefits to equate costs. 8 PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or benefits. 9 As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of approximately $382,179, not including additional damages and costs that are excluded or underreported in the incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents. 10 Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be minimal due to baseline prevalence of ILI-capable pipelines in all areas. 11 The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids cannot be quantified but could vary in frequency and size depending on the types of failures that are averted. Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected to enhance an operator’s ability to identify and address risk. The societal costs associated with incidents involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates for this requirement are equivalent to the average damages from less than three such incidents. This is relative to an annual average of 161 incidents in HCAs between 2010 and 2017. II. Background jbell on DSK3GLQ082PROD with RULES3 A. Detailed Overview This final rule addresses the requirements established by Congress in the 2011 Pipeline Safety Act, which are consistent with the emerging needs of the Nation’s hazardous liquid pipeline system. This final rule also advances an important safety need to adapt and expand risk-based safety practices considering changing markets and a growing national population whose location choices are in ever-closer proximity to existing pipelines. This final rule strengthens protocols for IM, including protocols for inspections, and improves and streamlines information collection to help drive risk-based identification of the areas with the greatest safety deficiencies. Hazardous Liquid Infrastructure Overview There are two major types of pipelines along the petroleum transportation route: Gathering pipeline systems, and crude oil and refined products pipeline systems. The location, construction and operation of these systems are generally regulated by Federal and State requirements. Gathering lines are typically smaller pipelines no more than 85⁄8 inches in diameter that transport petroleum from onshore and offshore production facilities. Hazardous liquid pipelines transport the crude oil from the gathering systems to refineries and from refineries to distribution centers. Hazardous liquid lines transport both crude and refined products, and can be hundreds of miles long. These lines may cross State and continental borders, and 3 Numbers in this table may not sum due to rounding. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 range in size from 2 to 48 inches in diameter. Hazardous liquid pipeline networks also include pump stations, which move the product through the pipelines, and storage terminals. Changes in product demand has also led to efforts by operators to increase pipeline capacity through flow-direction reversals or converting natural gas pipelines into hazardous liquid pipelines. Per PHMSA’s database, 43 percent of all hazardous liquid pipelines were installed prior to 1970.4 However, pipeline manufacturing, construction, and operational and maintenance practices have been improving steadily in recent decades, and some older pipes are susceptible to certain manufacturing or construction defects. For example, low-frequency electric resistance welded (ERW) pipe used from the early 1900s through the post-World War II construction boom that lasted well into the 1970s is vulnerable to seam-quality issues. Since the early 1970s, many improvements in pipe manufacturing and materials have been made, and steel and seam properties of pipe have improved with the increased use of high-frequency electric welded (HF– ERW), submerged arc welded (SAW), and seamless pipe (SMLS).5 In addition, smart pigs, which are tools that record information about the internal conditions of a pipeline, were not developed until the 1960s and 1970s 4 PHMSA’s Annual Report Mileage for Hazardous Liquid or Carbon Dioxide Systems; https:// www.phmsa.dot.gov/data-and-statistics/pipeline/ gas-distribution-gas-gathering-gas-transmissionhazardous-liquids. 5 HF–ERW steel pipe has a welded pipe seam made using a high frequency welding current. SMLS steel pipe has no longitudinal weld seam. SAW steel pipe has a weld seam made using a submerged welding arc in a bed of powdered flux to shield it from impurities. PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 prior to the adoption of the part 195 regulations. Since 2012, U.S. oil production has increased about 70 percent from approximately 2.4 to 3.4 Billion barrels annually 6 resulting in the United States becoming the world’s largest producer of liquid fuels in early 2014. Much of the recent increases in production have been in tight oil plays. Tight oil shale formations are heterogeneous and vary widely over relatively short distances and are subjected to fracking. Examples of tight oil formations include the Bakken Shale, the Niobrara Formation, Barnett Shale, and the Eagle Ford Shale in the United States. Per data from the U.S. Energy Information Administration (EIA), in 2017, tight oil plays accounted for approximately half of the U.S. production, balancing declining production in older plays. While tight oil from shale plays has historically been more difficult to extract, improvements in drilling and production methods, such as horizontal drilling and hydraulic fracturing, have made it economically recoverable. These tight oil plays are located both in regions that have had an oil extraction industry for decades and new regions, such as the Bakken region in North Dakota and Montana, that were not previously oil-producing areas. This has expanded U.S. refiners’ access to domestically produced crudes, and U.S. crude oil imports dropped by 7 percent since 2012.7 Additionally, exports have risen from minimal amounts in 2012 to 6 U.S. Energy Information Administration, Crude Oil Production. Producers extracted 2.4 billion barrels of crude oil from U.S. fields in 2012 and 3.4 billion barrels of crude oil in 2017. https:// www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_ a.htm. 7 EIA, U.S. Imports of Crude Oil (Thousands of Barrels per Day). https://www.eia.gov/dnav/pet/pet_ move_impcus_a2_nus_epc0_im0_mbblpd_a.htm. E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 over a million barrels per day in 2017.8 These supply increases and spatial changes in production patterns are creating wide-ranging impacts on liquid fuels transportation infrastructure. Regulatory History Congress established the current framework for regulating the safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline Safety Act (HLPSA) of 1979 (Pub. L. 96–129). The HLPSA provides the Secretary of Transportation (the Secretary) with the authority to prescribe minimum Federal safety standards for hazardous liquid pipeline facilities. That authority, as amended in subsequent reauthorizations, is currently codified in the Pipeline Safety Laws (49 U.S.C. 60101, et seq.). PHMSA is the agency within DOT that administers the Pipeline Safety Laws. PHMSA has issued a set of comprehensive safety standards for the design, construction, testing, operation, and maintenance of hazardous liquid pipelines. Those standards are codified in the Hazardous Liquid Pipeline Safety Regulations (49 CFR part 195). Part 195 applies broadly to the transportation of hazardous liquids or carbon dioxide by pipeline, including on the Outer Continental Shelf, with certain exceptions set forth by statute or regulation. A combination of prescriptive and management-based safety standards is used (i.e., an objective is specified, but the method of achieving that objective is not). Risk management principles play a key role in the IM requirements. PHMSA exercises primary regulatory authority over interstate hazardous liquid pipelines, and the owners and operators of those facilities must comply with safety standards in part 195. States may apply to PHMSA for a certification to conduct inspections of intrastate hazardous liquid pipelines. Public utility commissions administer most State pipeline safety programs. These State authorities must adopt the Pipeline Safety Regulations as part of a certification or agreement with PHMSA, but may establish more stringent safety standards for intrastate pipeline facilities within their State regulatory authorities. PHMSA is precluded from regulating the safety standards or practices for an intrastate pipeline facility if a State is currently certified to regulate that facility. States certified to regulate their intrastate lines can also enter into agreements with PHMSA to 8 EIA, U.S. Exports of Crude Oil (Thousand Barrels per Day). https://www.eia.gov/dnav/pet/pet_ move_exp_dc_NUS–Z00_mbblpd_a.htm. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 serve as an agent for inspecting interstate facilities, and they can receive Federal monetary grants to off-set the costs of those State inspections. In 2000 and 2002, the Office of Pipeline Safety (OPS) published regulations requiring IM programs for hazardous liquid pipeline operators in response to a hazardous liquid incident in Bellingham, WA, in 1999 that killed three people.9 The regulations were broad-reaching and supplemented PHMSA’s prescriptive safety requirements with performance and process-oriented requirements. The approach aimed to set expectations for operators while giving them a degree of flexibility in how they complied with those expectations. The objectives of the IM regulations were to accelerate and improve the quality of integrity assessments conducted on pipelines in areas with the highest potential for adverse consequences; promote a more rigorous, integrated, and systematic management of pipeline integrity and risk by operators; strengthen the government’s role in the oversight of pipeline operator integrity plans and programs; and increase the public’s confidence in the safe operation of the Nation’s pipeline network. In January 2011, PHMSA published the Hazardous Liquid Integrity Management Progress Report,10 which reported on PHMSA’s progress in achieving the program objectives and examined accident trends. The report found that the IM rule and PHMSA’s rigorous oversight of operator compliance with the rule are contributing to improved safety performance, including a reduction in the frequency of significant accidents and a decrease in volume spilled in significant accidents. PHMSA’s Progress on Integrity Management The original part 195 Pipeline Safety Regulations were not designed with risk management in mind. In the mid-1990s, following models from other industries such as nuclear power, PHMSA started to explore whether a risk-based approach to regulation could improve safety of the public and the environment. During this time, PHMSA 9 65 FR 75378; December 1, 2000; Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With 500 or More Miles of Pipeline). 67 FR 1650; January 14, 2002; Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Repair Criteria). 67 FR 2136; January 16, 2002; Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With Less Than 500 Miles of Pipelines). 10 https://primis.phmsa.dot.gov/iim/IM_Jan2011_ StatusReport_01_23_11.pdf. PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 52263 found that many operators were performing forms of IM that varied in scope and sophistication but there were not consistent minimum standards or requirements. Since the implementation of the IM regulations more than 15 years ago, many factors have changed. Most importantly, there have been sweeping changes in the oil industry, and the Nation’s relatively safe but aging pipeline network faces increased pressures from these changes. Longidentified pipeline safety issues, some of which IM set out to address, remain problems. Infrequent but severe accidents indicate that some pipelines continue to be vulnerable to failures stemming from, among other things, outdated construction methods or materials. Some severe pipeline accidents have occurred in areas outside HCAs where the application of IM principles is not required.11 The current IM program is both a set of regulations and an overall regulatory approach to improve pipeline operators’ ability to identify and mitigate the risks to their pipeline systems. On the operator level, an IM program includes adopting procedures and processes to identify HCAs, which are areas with the greatest population density and environmental sensitivity; determining likely threats to the pipeline within the HCA; evaluating the physical integrity of the pipe within the HCA; and repairing or remediating any pipeline defects found. Because these procedures and processes are complex and interconnected, effective implementation of an IM program relies on continual evaluation and data integration. Operators have made great progress towards achieving the IM objectives. Operators have an improved understanding of the precise locations of their HCAs—those areas where integrity assessments and other protective measures spelled out in the IM rule must be taken to assure public safety and environmental protection. During an incident, petroleum can spread over large areas and cause environmental damage. The IM protections for HCAs are designed to account for the potential environmental and community risks from oil releases. Per PHMSA’s hazardous liquid annual 11 Per PHMSA annual report data accessed May 14, 2019, 1677 non-HCA accidents have occurred since 2010. Of these accidents, 908 resulted in a ‘‘large’’ spill, which for reporting purposes is defined as those spills where there was a fatality, injury, fire, explosion, water contamination, property damage of greater than $50,000, or an unintentional loss of product greater than 210 gallons (5 bbls). E:\FR\FM\01OCR3.SGM 01OCR3 52264 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 data, 42 percent of the Nation’s hazardous liquid pipelines 12 can potentially affect HCAs and thus receive the enhanced level of integrity assessment and protection mandated by the IM rule. As required by the IM rule, operators have also conducted baseline integrity assessments on all pipelines that could affect HCAs and have begun conducting reassessments of these same pipeline segments. Through this requirement to assess their pipelines, operators now have an improved understanding of the condition of pipelines in these safety-sensitive areas. According to PHMSA’s January 2011 Hazardous Liquid Integrity Management Progress Report, which tracked the progress and effectiveness of the IM program in its first decade, as a result of these initial baseline assessments, operators have made more than 7,600 repairs of anomalies that required immediate attention, remediated over 28,000 other conditions on a scheduled basis, and addressed an additional 79,000 anomalies that were not required to be addressed by the IM rule, thus significantly improving the condition of the Nation’s pipelines. However, based on recent accidents and mandates from the 2011 Pipeline Safety Act, improvement is still needed in the areas of data integration and their use in risk modelling, risk analysis, and to identify and implement additional preventive and mitigative measures to reduce risk. Improving data integration is critical, as the integrity assessment provisions of the rule only address some of the causes of pipeline failures. Inadequate Leak Detection, Exposure to Weather, Increased Use, and Age Can Increase the Risk of Pipeline Incidents Risk factors for pipeline safety issues stem from many sources, including manufacturing issues, external weather and environmental factors, land-use activities near pipelines, other operational issues, and age-related integrity issues. On July 25, 2010, a segment of a 30inch-diameter pipeline called Line 6B, owned and operated by Enbridge Incorporated, ruptured in a wetland area in Marshall, MI. Per §§ 195.450 and 195.6, this area was identified by the operator as an ‘‘other populated area,’’ which meant it was within an HCA. Per the NTSB’s Pipeline Accident Report on the incident, the rupture occurred during the last stages of a planned 12 https://phmsa.dot.gov/portal/site/PHMSA/ menuitem.6f23687cf7b00b0f22e4c6962d9c8789/? vgnextoid=a872dfa122a1d110VgnVCM1000009 ed07898RCRD&vgnextchannel=3430fb649a 2dc110VgnVCM1000009ed07898RCRD&vgnextfmt= print. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 shutdown and was not discovered or addressed for over 17 hours. During the time lapse, Enbridge twice pumped additional oil (81 percent of the total release) into Line 6B during two startups; the total release was estimated by Enbridge to be 843,444 gallons of crude oil.13 The oil saturated the surrounding wetlands and flowed into the Talmadge Creek and the Kalamazoo River. In all, 4,632 acres of land were impacted, 346 animals were killed, 4,208 animals were oiled, and fish and benthic invertebrate communities were impacted. Further, approximately 100,000 recreational user-days were lost, including activities like fishing and boating, and general shoreline park and trail use. The incident also resulted in losses of tribal use, as the Kalamazoo River is used by two tribes for water travel; subsistence; and medicinal, economic, educational, and ceremonial services.14 This incident motivated a reexamination of hazardous liquid pipeline safety. The NTSB made recommendations to PHMSA and the regulated industry regarding the need to improve hazardous liquid pipeline safety. Congress also directed PHMSA to reexamine many of its safety requirements, including the expansion of IM regulations to more hazardous liquid pipelines. Other recent accidents, including a pair of related failures that occurred in 2010 on a crude oil pipeline in Salt Lake City, UT, corroborated the significance of having an adequate means for identifying and responding to leaks in all locations. The Nation’s pipeline system also faces significant risk from failure due to extreme weather events and natural disasters, such as hurricanes, floods, mudslides, tornadoes, and earthquakes. On January 17, 2015, a breach in the Bridger Pipeline Company’s Poplar system resulted in a spill into the Yellowstone River near the town of Glendive, MT, releasing 31,835 gallons (758 barrels) 15 of crude oil into the river 13 National Transportation Safety Board: ‘‘Enbridge Incorporated Hazardous Liquid Pipeline Rupture and Release, Marshall, Michigan, July 25, 2010,’’ Accident Report NTSB/PAR–12/01, adopted 2012; https://www.ntsb.gov/investigations/ AccidentReports/Reports/PAR1201.pdf. 14 U.S. Fish and Wildlife Service: ‘‘Final Damage Assessment and Restoration Plan/Environmental Assessment for the July 25–26, 2010 Enbridge Line 6B Oil Discharges near Marshall, MI;’’ Sections 1.4—Summary of Natural Resource Injuries and 3.0—Injury Assessment and Quantification. October 2015. https://www.fws.gov/midwest/es/ec/nrda/ MichiganEnbridge/pdf/FinalDARP_EA_ EnbridgeOct2015.pdf. 15 PHMSA Database: ‘‘Operator Information: Incident and Mileage Data: Bridger Pipeline LLC,’’ https://primis.phmsa.dot.gov/comm/reports/ operator/OperatorIM_opid_ 31878.html?nocache=4851%20-%20_Incidents_ tab_3#_OuterPanel_tab_2. PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 and affecting local water supplies. Information indicated over 100 feet of pipeline was exposed on the river bottom, and the release point was near a girth weld. A depth of cover survey indicated sufficient cover in late 2011,16 but the area experienced localized flooding in early 2014. A previous crude oil spill into the Yellowstone River in 2011 near Laurel, MT, was caused by channel migration and river bottom scour, leaving a large span of the pipeline exposed to prolonged current forces and debris washing downstream in the river. Those external forces damaged the exposed pipeline. In October 1994, flooding along the San Jacinto River led to the failure of eight hazardous liquid pipelines and undermined a number of other pipelines. The escaping products were ignited, leading to 547 people in the area suffering extensive smoke inhalation or burn injuries.17 According to PHMSA’s Accident and Incident Data for hazardous liquid pipelines, from 2010 to 2017, there were 145 reportable incidents 18 in which storms or other severe natural force conditions damaged pipelines and resulted in their failure. Operators reported total damages of over $232 million from these incidents.19 PHMSA has issued several Advisory Bulletins to operators warning about extreme weather events and the consequences of flooding events, including river scour and river channel migration. Further, in December 2017, the American Petroleum Institute issued a Recommended Practice 1133 that provided guidance to operators on how to identify at-risk river crossings and take measures to reduce such risks before, during, and after flooding- and river-scour events. In addition to external weather and environmental threats, changing production and shipment patterns are increasing stress on the Nation’s 16 PHMSA, Corrective Action Order, CPF No. 5– 2015–5003H, page 4, January 23, 2015; https:// www.phmsa.dot.gov/staticfiles/PHMSA/ DownloadableFiles/Files/Pipeline/520155003H_ Corrective%20Action%20Order_01232015.pdf. 17 NTSB, Pipeline Special Investigation Report, ‘‘Evaluation of Pipeline Failures During Flooding and of Spill Response Actions, San Jacinto River Near Houston, Texas, October 1994;’’ NTSB/SIR– 96/04, Adopted September 6, 1996. 18 Reporting thresholds for hazardous liquid pipelines are established at § 195.50. Operators must report any failures of a hazardous liquid pipeline resulting in any of the following: (1) An explosion or fire not intentionally set by the operator, (2) A release of 5 gallons or more of hazardous liquid or carbon dioxide, (3) The death of an individual, (4) Personal injury requiring hospitalization, (5) Estimated property damage exceeding $50,000. 19 PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/ pipeline/pipeline-incident-flagged-files. E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 pipeline system. Shifting production to tight oil production like shale plays have changed U.S. oil production locations, as well as the types of crude transported in the Nation’s pipelines. The U.S. pipeline system has previously moved crude oil from interior production regions to the Gulf of Mexico refineries, and petroleum products from Gulf Coast refineries to the interior of the country. However, increased tight oil production requires significant infrastructure expansion in new areas, and shifting production areas are changing the patterns of oil transport. Many operators are adapting their systems to move crude oil to markets formerly dependent on imports by modifying existing pipelines. These modifications can be made by reversing flow directions and repurposing natural gas pipelines; in some cases pipeline expansion projects can also increase pumping capability with minimal alterations of the pipeline itself. Reversing a pipeline’s flow, modifying pump station placement and operation, changing commodities, or making other changes to a pipeline’s historical hydraulic gradient can impose new stresses on the system due to altered pressure gradients, cycling, and flow rates. Furthermore, certain commodities and low flow rates may create new risks of internal corrosion. Occasional failures on hazardous liquid pipelines have occurred after operational changes that include flow reversals and product changes. PHMSA has noticed several recent or proposed flow reversals and product changes on a number of hazardous liquid and gas transmission lines. In response to this phenomenon, on September 18, 2014, PHMSA issued an Advisory Bulletin 20 notifying operators of the potentially significant impacts such changes may have on the integrity of a pipeline. Data indicate that some pipelines also continue to be vulnerable to issues stemming from outdated construction methods or materials. Much of the older pipe in the Nation’s pipeline infrastructure was made before the 1970s using techniques that have proven to contain latent defects due to the manufacturing process.21 Such defects cause the pipe to be susceptible to developing hook cracks or other 20 PHMSA: ‘‘Pipeline Safety: Guidance for Pipeline Flow Reversals, Product Changes and Conversion to Service’’ Advisory Bulletin, 79 FR 56121, September 18, 2014; https:// www.phmsa.dot.gov/staticfiles/PHMSA/ DownloadableFiles/Advisory%20Notices/ADB2014-04_Flow_Reversal.pdf. 21 See https://primis.phmsa.dot.gov/comm/ FactSheets/FSPipeManufacturingProcess.htm for more information about pipe manufacturing processes and known latent defects. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 anomalies that may, over time, lead to failures if they are not timely repaired. For example, line pipe manufactured using low-frequency electric resistance welding is susceptible to seam failure. A substantial amount of this type of pipe is still in service; per PHMSA’s ‘‘Miles by Decade of Installation Inventory Reports’’ for hazardous liquid lines, there were 92,271 miles of pre-1970s pipe still in service in 2017.22 The IM regulations include specific requirements for evaluating such pipe if located in HCAs, but infrequent-yetsevere failures that are attributed to longitudinal seam defects continue to occur. Per PHMSA’s Accident and Incident database, between 2010 and 2017, 84 reportable incidents were attributed to seam failures, resulting in over $220 million of property damage.23 24 In the final rule, PHMSA strengthens the IM requirements to identify and respond to the increased pipeline risks resulting from operational changes, weather and associated geotechnical hazards, and increased use and age of a pipe. Enhanced Collection of Data To keep the public safe and to protect the Nation’s energy security and reliability, operators and regulators must have an intimate understanding of their entire pipeline system, including threats and operations. However, with operators who are not required to report certain information on certain currently unregulated pipelines, and with aging pipelines that are not modernized for internal inspection, there continue to be data gaps that make it hard to fully understand the extent of the potential safety risks to the integrity of the Nation’s pipeline system. PHMSA’s regulations exempt rural gathering pipelines and gravity pipelines. Gravity pipelines carry product by means of gravity, and many gravity lines are short and within tank farms or other pipeline facilities. However, some gravity lines are longer and can build up high pressures. PHMSA is aware of gravity lines that 22 PHMSA’s Annual Report Mileage for Hazardous Liquid or Carbon Dioxide Systems; https://www.phmsa.dot.gov/data-and-statistics/ pipeline/gas-distribution-gas-gathering-gastransmission-hazardous-liquids. 23 PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/ pipeline/pipeline-incident-flagged-files. 24 The data can be narrowed down by selecting the ‘‘hl2010toPresent’’ Excel spreadsheet. Cell ‘‘CR’’ indicates the identified location of the failure and whether the failure was in the pipe body or in the pipe seam. If it was identified as a pipe seam failure, Cells ‘‘CW’’ and ‘‘CX’’ provide additional information on pipe seam type and pipe seam details, respectively. PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 52265 traverse long distances with significant elevation changes, which could have significant consequences in the event of a release. Both gravity and gathering lines are currently excluded from reporting requirements, leaving large gaps in PHMSA’s knowledge of these unregulated pipeline systems. This is especially true because much of operators’ and PHMSA’s data is obtained through testing and inspection under IM requirements, which are not currently required for gathering and gravity lines. To assess a pipeline’s integrity, operators generally choose between three methods of testing a pipeline: Inline inspection (ILI), pressure testing, and direct assessment (DA). In 2017, PHMSA estimates that slightly over 90 percent of the hazardous liquid line mileage in HCAs is already piggable and almost 90 percent of these lines were being inspected with ILI tools. Operators perform ILIs by using special tools, sometimes referred to as ‘‘smart pigs,’’ which are usually pushed through a pipeline by the pressure and flow rate of the product being transported. As the tool travels through the pipeline, it identifies and records potential pipe defects or anomalies. Because these tests can be performed with product in the pipeline, the pipeline does not have to be taken out of service for testing to occur, which can reduce cost to the operator and possible service disruptions to consumers. Further, ILI is a non-destructive testing technique, and it can be less costly on a per-unit basis to perform than other assessment methods. However, a very small portion of hazardous liquid pipe segments cannot be inspected through ILI because they are too short in length, which makes getting accurate ILI tool results impractical due to tool speed variations. Other hazardous liquid pipelines might not be inspected through ILI because they do not have enough operating pressure or flow rate to run the tool. Pipeline operators typically use pressure tests to determine the integrity (or strength) of the pipeline immediately after construction and before placing the pipeline in service. In a pressure test, a test medium (typically water) inside the pipeline is pressurized to a level greater than the normal operating pressure of the pipeline. This test pressure is held for a number of hours to ensure there are no leaks in the pipeline. Direct assessment is the evaluation of various locations on a pipeline for corrosion threats. Operators will review operational records and indirectly inspect the pipeline with coating surveys, such as close interval, direct E:\FR\FM\01OCR3.SGM 01OCR3 52266 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 current voltage gradient, and alternating current voltage gradient surveys, to detect areas where the protective, anticorrosion coating applied to a pipeline may be faulty, as corrosion may be more likely in these locations. Operators subsequently excavate and examine areas that are likely to have suffered from corrosion. DA can be costly to use without targeting specific locations. A limited number of specific locations, however, may not give an accurate representation of the condition of lengths of entire pipeline segments. Ongoing research appears to indicate that ILI and hydrostatic pressure ‘‘spike’’ testing are more effective than DA for identifying pipe conditions related to cracking defects such as dents with stress cracks, stress corrosion cracking (SCC), selective seam weld corrosion (SSWC), and other seam-type cracking.25 Hydrostatic testing of hazardous liquid pipelines requires testing to at least 125 percent of the maximum operating pressure (MOP) for at least 4 continuous hours and an additional 4 hours at a pressure of at least 110 percent of MOP if the pipe is not visible. If there is concern about pipe cracks that might grow due to pressure cycling, operating stress levels, environmental conditions, and fatigue, then a spike test at a pressure of up to or over 139 percent of MOP for a short period (up to a 30-minute hold time or longer) may be conducted. A spike test detects pipe body and seam cracks by causing any cracks that would later grow to failure to fail during the hydrostatic test. Both regulators and operators have expressed interest in improving ILI methods as an alternative to hydrostatic testing for better risk evaluation and management of pipeline safety. Hydrostatic pressure testing can result in substantial costs and occasional disruptions in service, whereas ILI testing can obtain data that is not otherwise obtainable via other assessment methods, such as pipe wall loss, dents, and cracking. In this final rule, PHMSA is addressing data gaps and increasing the 25 See: Comprehensive Study to Understand Longitudinal ERW Seam Research & Development study task reports: Battelle Final Reports (‘‘Battelle’s Experience with ERW and Flash Weld Seam Failures: Causes and Implications’’—Task 1.4), Report No. 13–002 (‘‘Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams’’—Subtask 2.4), Report No. 13–021 (‘‘Predicting Times to Failure for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue’’—Subtask 2.5), and ‘‘Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1’’—Task 4.5), which can be found online at: https:// primis.phmsa.dot.gov/matrix/ PrjHome.rdm?prj=390. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 quality of data collected by expanding the reporting requirements to cover both gathering and gravity lines and requiring that all lines in HCAs be piggable for a better understanding of pipeline characteristics. The final rule will also require operators to fully integrate their pipeline data across all data sources to close any remaining gaps. Looking at Risk Beyond HCAs In addition to improving IM programs for the pipe that they already cover, PHMSA understands the importance of carefully reconsidering the scope of the areas covered by IM requirements. While PHMSA’s hazardous liquid IM program manages risks primarily by focusing oversight on areas with the greatest population density and environmental sensitivity, it is imperative to protect the safety of environmental resources and communities throughout the country. The changing landscape of production, consumption, and product movement merits a fresh look at the current scope of IM coverage. The current definition of an HCA uses Census Bureau definitions of urbanized areas or areas with a concentrated population.26 The HCA definition also encompasses ‘‘unusually sensitive areas,’’ including drinking water or ecological resource areas and commercially navigable waterways. However, liquid spills, even outside HCAs, can result in environmental damage necessitating clean up, restoration costs, and lost use and nonuse values. If operators do not periodically assess and repair their pipelines, liquid spills are more likely to occur. In fact, devastating incidents have occurred outside of HCAs in rural areas where populations are sparse, and operators have not been required to assess their lines as frequently as lines covered by IM. Per PHMSA’s databases, between 2010 and 2017, significant incidents at hazardous liquid facilities accounted for over 993,097 barrels spilled, 24 injuries, and 10 fatalities. Out of those, over 702,091 barrels spilled, 10 injuries, and four fatalities occurred in non-HCA areas.27 These 26 Specifically, § 195.450 states that a high population area is an urban area, as defined and delineated by the Census Bureau, that contains 50,000 or more people and has a population density of at least 1,000 people per square mile, and an other populated area is a place, as defined and delineated by the Census Bureau, that contains a concentrated population, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial area. 27 PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/ pipeline/pipeline-incident-flagged-files. PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 data show that ruptures with the potential to affect populations, the environment, or commerce, can occur anywhere on the Nation’s pipeline system. If constant improvement and zero incidents are goals for pipeline operators,28 extending and prioritizing IM assessments and principles to all parts of pipeline networks is an effective way to achieve those goals. Extending IM assessments and principles to nonHCAs will help clarify vulnerabilities and prioritize improvements, and this final rule takes important steps towards developing that approach and will lead operators to gather valuable information they may not have collected if regulations were not in place. In this final rule, PHMSA is requiring operators to assess onshore, piggable pipelines outside of HCAs periodically using ILI or other technology, if appropriate, to detect (and remediate) anomalies in all locations within their pipeline systems. PHMSA is providing operators with deadlines to verify their segment analyses to identify any new HCAs and implement the appropriate actions. These changes would ensure the remediation of anomalous conditions that could potentially impact people, property, or the environment, while at the same time allowing operators to allocate their resources based on pipeline risks and the vulnerability of surrounding areas. Recent Developments in Hazardous Liquid Pipeline Safety Regulation On October 18, 2010, PHMSA posed a series of questions to the public in the context of an ANPRM titled ‘‘Pipeline Safety: Safety of On-Shore Hazardous Liquid Pipelines’’ (75 FR 63774). In that document, PHMSA sought comments on several proposed changes to part 195, including: (1) The scope of part 195 and existing regulatory exceptions, (2) Criteria for designation of HCAs, (3) Leak detection and emergency flow restricting devices, (4) Valve spacing, (5) Repair criteria outside of HCAs, and (6) Stress corrosion cracking. The questions in this ANPRM considered topics relating to the statutory mandates; the post-Marshall, MI, NTSB and GAO recommendations; and other pipeline safety mandates. Twenty-one organizations and individuals submitted comments in response to the ANPRM. PHMSA reviewed the received comments, the 2011 Pipeline Safety Act, 28 Major trade associations, including API and INGAA, have publicly committed to a goal of zero incidents. See: https://www.api.org/oil-and-naturalgas/wells-to-consumer/transporting-oil-natural-gas/ pipeline/pipeline-safety and https://www.ingaa.org/ File.aspx?id=20463 for more details. E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations and the NTSB and GAO recommendations, and responded in the subsequent NPRM published on October 13, 2015, (80 FR 61609). In summary, the NPRM addressed the following areas: (1) Reporting requirements for gravity lines, (2) Reporting requirements for gathering lines, (3) Inspections of pipelines following extreme weather events and natural disasters, (4) Periodic assessments of pipelines not subject to IM, (5) Repair criteria, (6) Expanded use of leak detection systems, (7) Increased use of in-line inspection tools, and (8) Clarifying other requirements. A summary of comments and responses to those comments are provided later in the document. The ANPRM and NPRM may be viewed at https:// www.regulations.gov by searching for Docket No. PHMSA–2010–0229. jbell on DSK3GLQ082PROD with RULES3 B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 After the issuance of the ANPRM on October 18, 2010, the 2011 Pipeline Safety Act included several statutory requirements related directly to the topics being considered in the ANPRM. The related topics and statutory citations that PHMSA considered within the context of this rulemaking include, but are not limited to: • Section 5(f)—Requires, if appropriate, regulations issued by the Secretary to expand integrity management system requirements, or elements thereof, beyond highconsequence areas. These regulations are to be dependent on an evaluation and report of whether integrity management system requirements, or elements thereof, should be expanded beyond high-consequence areas; • Section 8—Requires, if appropriate, regulations regarding leak detection on hazardous liquid pipelines and establishing leak detection standards. These regulations are to be dependent on a report on the analysis of the technical limitations of current leak detection systems, including the ability of the systems to detect ruptures and small leaks that are ongoing or intermittent, and what can be done to foster development of better technologies, and an analysis of the practicability of establishing technically, operationally, and VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 economically feasible standards for the capability of such systems to detect leaks, and the safety benefits and adverse consequences of requiring operators to use leak detection systems; • Section 14—Permits PHMSA to issue regulations for pipelines transporting non-petroleum fuels, such as biofuels; • Section 21—Requires a review on the regulation of Gas (and Hazardous Liquid) Gathering Lines and the issuance of further regulations, if appropriate; and • Section 29—Requires that operators consider seismicity when evaluating pipeline threats. C. National Transportation Safety Board Recommendation On July 10, 2012, shortly after the 2011 Pipeline Safety Act was passed, the NTSB issued its accident investigation report on the Marshall, MI, accident. In it, the NTSB made additional recommendations to update the hazardous liquid pipeline regulations. Pertaining directly to this rule, the NTSB issued recommendation P–12–04, which addressed the ‘‘discovery of condition’’ as follows: • NTSB Recommendation P–12–4: ‘‘Revise Title 49 Code of Federal Regulations 195.452(h)(2), the ‘discovery of condition,’ to require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators notify the Pipeline and Hazardous Materials Safety Administration and provide an expected date when adequate information will become available.’’ D. Summary of Each Topic This final rule amends the Federal Pipeline Safety Regulations to address the following topics. Details of the changes in this rule are discussed in this document in Section IV, ‘‘Analysis of Comments and PHMSA Response,’’ and Section V, ‘‘Section-by-Section Analysis.’’ (1) Extend Certain Reporting Requirements to Certain Gravity and Rural Hazardous Liquid Gathering Lines Gravity lines are pipelines that carry product by means of gravity and are PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 52267 currently exempt from PHMSA regulations. Many gravity lines are short and within tank farms or other pipeline facilities; however, some gravity lines are longer and can build up large amounts of pressure. Further, certain gravity lines may have significant elevation changes, which can lead to serious consequences in the event of a release. For PHMSA to effectively analyze the safety performance and risk of gravity lines, PHMSA needs basic data about those pipelines. The agency has the statutory authority to gather data for all gravity lines (49 U.S.C. 60117(b)). Accordingly, PHMSA is amending the Pipeline Safety Regulations (PSR) to require that the operators of certain gravity lines comply with requirements for submitting annual, safety-related condition, and incident reports. PHMSA estimates that, at most, five hazardous liquid pipeline operators will be affected. Based on comments to the ANPRM from the American Petroleum Institute and the Association of Oil Pipelines (API–AOPL), 3 operators have approximately 17 miles of gravity-fed pipelines. PHMSA estimated that proportionally 5 operators would have 28 miles of gravity-fed pipelines. PHMSA is also amending the PSR to extend the annual, accident, and safetyrelated condition reporting requirements of part 195 to all hazardous liquid gathering lines. The Hazardous Liquid Pipeline Safety Act of 1979 (Pub. L. 96–129) did not mandate the regulation of rural gathering lines because at that time they were not thought to present a significant enough risk to public safety to justify Federal regulation based on the data available at that time. However, the Pipeline Safety Act of 1992 (Pub. L. 102–508) authorized the issuance of safety standards for regulated rural gathering lines based on a consideration of certain factors and subject to certain exclusions. When PHMSA adopted the current requirements for regulated rural gathering lines, the agency made judgments in implementing those statutory provisions based on the information available at that time. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 52268 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations Recent data indicates, however, that PHMSA regulates less than 4,000 miles of the approximately 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States.29 That means that about 90 percent of the onshore gathering line mileage is not currently subject to any minimum Federal pipeline safety standards. The NTSB has also raised concerns about the safety of hazardous liquid gathering lines in the Gulf of Mexico and its inlets,30 which are only subject to certain inspection and reburial requirements. In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for hazardous liquid gathering lines. Section 195.1(a)(4)(ii) states that part 195 applies to a ‘‘regulated rural gathering line as provided in § 195.11.’’ PHMSA published a final rule on June 3, 2008 (73 FR 31634), that prescribed certain safety requirements for regulated rural gathering lines (i.e., the filing of accident, safety-related condition, and annual reports; establishing the MOP in accordance with § 195.406; installing line markers; and establishing programs for public awareness, damage prevention, corrosion control, and operator qualification of personnel). The June 2008 final rule did not establish safety standards for all rural hazardous liquid gathering lines. Some of those lines cannot be regulated by statute (i.e., 49 U.S.C. 60101(b)(2)(B) states that ‘‘the definition of ‘‘regulated gathering line’’ for hazardous liquid may not include a crude oil gathering line that has a nominal diameter of not more than 6 inches, is operated at low pressure, and is in a rural area that is not unusually sensitive to environmental damage’’), and Congress did not remove this exemption in the 2011 Pipeline Safety Act. PHMSA is currently statutorily limited to regulating gathering lines in HCAs and ‘‘regulated rural gathering lines,’’ which are defined in § 195.11 to mean onshore gathering lines in a rural area that meet certain criteria (i.e., has a nominal diameter from 65⁄8 in. (168 mm) to 85⁄8 in. (219.1 mm), is in or within 1⁄4 mile of an unusually sensitive area as defined in § 195.6, and operates at a maximum pressure established under § 195.406). This limitation leaves gaps in the regulation of rural gathering lines not classified as regulated rural gathering lines. Further, PHMSA currently collects no data on unregulated gathering lines. This lack of data prevents PHMSA from being able to determine whether current regulations should be applied to currently unregulated gathering lines. Therefore, in this final rule, PHMSA is requiring reporting on all hazardous liquid gathering lines and will consider, based on the nature of the data gathered, the appropriateness of additional regulatory requirements, if any, for hazardous liquid gathering lines in the future. The final rule, however, does not address or require data collection for transportation-related flow lines until further study and cost analyses can be conducted. PHMSA notes that, per Section 12 of the 2011 Pipeline Safety Act, Congress has provided PHMSA with the authority to collect data on pipelines transporting oil off the grounds of the well where it originated and across areas not owned by the producer, regardless of the extent to which the oil has been processed, if at all. Aside from this rulemaking, PHMSA may consider collecting these data in the future. As discussed above, any decision PHMSA makes to expand its oversight of gathering lines beyond what is currently regulated will be driven by risk assessment and analysis based on evaluations of incident and accident data, data related to infrastructure, and further technological advancements such as the unconventional production practices used in shale formations. 29 PHMSA, ‘‘Hazardous Liquid Pipeline Miles and Tanks,’’ https://hip.phmsa.dot.gov/ analyticsSOAP/saw.dll?Portalpages&NQUser= PDM_WEB_USER&NQPassword=Public_Web_ User1&PortalPath=%2Fshared%2FPDM%20Public %20website%2F_portal%2FPublic %20Reports&Page=Infrastructure&Action= Navigate&col1=%22PHP%20-%20Geo%20Location %22.%22State%20Name%22&val1=%22%22, retrieved 11/20/2018. 30 Deborah Hersman, Testimony before the Subcommittee on Surface Transportation and Merchant Marine Infrastructure, Safety, and Security Committee on Commerce, Science, and Transportation, United States Senate Hearing on Ensuring the Safety of our Nation’s Pipelines, Washington DC, 6/24/2010. https://www.ntsb.gov/ news/speeches/DHersman/Pages/Testimony_ before_the_Subcommittee_on_ Surface_Transportation_and_Merchant_Marine_ Infrastructure_Safety_and_Security_Committ.aspx. (2) Require Inspections of Pipelines in Areas Affected by Extreme Weather and Natural Disasters Extreme weather has been a contributing factor in several pipeline failures. For example, in 1994, flooding in Texas led to river scour and ground movement that caused the failure of eight pipelines and the release of more than 35,000 barrels of hazardous liquids into the San Jacinto River. Some of that released product also ignited, causing minor burns and other injuries to nearly 550 people according to the NTSB. In July 2011, a pipeline failure associated with river bottom scour occurred near Laurel, MT, causing the release of an VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 estimated 1,000 barrels of crude oil into the Yellowstone River. That area had experienced extensive flooding due to warm weather causing the rapid melting of large snowpack levels in the weeks leading up to the failure. The operator estimated the cleanup costs at approximately $135 million. In January 2015, another pipeline failure caused by river bottom scour again occurred on the Yellowstone River, spilling approximately 758 barrels of crude oil into the river, causing the shutdown of nearby drinking-water intakes.31 Additionally, on October 21, 2016, extreme localized flooding, soil erosion, and ground movement caused a release of over 1,238 barrels of gasoline into the Loyalsock Creek in Lycoming County, PA. Further, on March 20, 2018, heavy rain caused a pipeline to rupture and release 1,400 barrels of diesel fuel into Big Creek at Solitude, IN. Specifically, a girth weld on the pipeline ruptured due to land slippage caused by the saturated soil. Weather events and natural disasters that can cause river scour, soil subsidence or ground movement may subject pipelines to additional external loads, which could cause a pipeline to fail. These conditions can pose a threat to the integrity of pipeline facilities if those threats are not promptly identified and mitigated. While the existing regulations provide for design standards that consider the load that may be imposed by geological forces, events like the ones described above can quickly impact the safe operation of a pipeline and have severe consequences if not mitigated and remediated as quickly as possible. PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to communicate the potential for damage to pipeline facilities caused by severe flooding, including actions that operators should consider taking to ensure the integrity of pipelines in the event of flooding, river scour, river channel migration, and earth movement.32 As PHMSA has noted in a series of Advisory Bulletins, hurricanes are also capable of causing extensive damage to both offshore and inland pipelines (e.g., Hurricane Ivan, September 23, 2004 (69 FR 57135); Hurricane Katrina, September 7, 2005 31 https://deq.mt.gov/Portals/112/DEQAdmin/DIR/ Documents/Bridger%20Consent%20Order/Final %20Bridger%20Consent%20Order.pdf?ver=201702-09-121902-843. 32 ‘‘Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,’’ April 9, 2015, 80 FR 19114; and January 19, 2016, 81 FR 2943. See also ‘‘Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards,’’ May 2, 2019, 84 FR 18919. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations (70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)). These events demonstrate the importance of working to ensure that our Nation’s waterways and the public are adequately protected from pipeline risks in the event of a natural disaster or extreme weather. PHMSA is aware that many operators perform inspections following such events; however, because it is not a requirement, some operators do not. Therefore, PHMSA is amending the PSR to require that operators commence inspection of their potentially affected assets within 72 hours after the cessation of an extreme weather event such as a hurricane, flood, landslide, earthquake, or other natural disaster that has the likelihood to damage infrastructure. PHMSA would not expect operators to comply with these provisions for weather events when, considering the physical characteristics, operating conditions, location, and prior history of the affected system, the event would not have a likelihood of damage to the pipeline. For example, extreme weather events would not include rain events that do not exceed the high-water banks of the rivers, streams or beaches in proximity to the pipeline; rain events that do not result in a landslide in the area of the pipeline; storms that do not produce winds at tropical storm or hurricane level velocities; or earthquakes that do not cause soil movement in the area of the pipeline. Under this requirement, an operator must inspect all potentially affected pipeline facilities following these types of events to detect conditions that could adversely affect the safe operation of the pipeline. The operator must consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining whether the event necessitates an inspection as well as the appropriate method for performing the inspection. If the event creates a likelihood that there is damage to pipeline infrastructure, the operator must commence an inspection within 72 hours after the cessation of the event, defined as the point in time when the area can be safely accessed by personnel and equipment, including availability of personnel and equipment, required to perform the inspection. PHMSA has found that 72 hours is reasonable and achievable in most cases based on prior observations of extreme events. If an operator finds an adverse condition, the operator must take appropriate remedial action to ensure the safe operation of a pipeline based on the information obtained from the VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 inspection. Such actions might include, but are not limited to: • Reducing the operating pressure or shutting down the pipeline; • Isolating pipelines in affected areas and performing ‘‘stand up’’ leak tests; • Modifying, repairing, or replacing any damaged pipeline facilities; • Preventing, mitigating, or eliminating any unsafe conditions in the pipeline rights-of-way; • Performing additional patrols, depth of cover surveys, ILI or hydrostatic tests, or other inspections to confirm the condition of the pipeline and identify any imminent threats to the pipeline; • Implementing emergency response activities with Federal, State, or local personnel; and • Notifying affected communities of the steps that can be taken to ensure public safety. This requirement is based on the experience of PHMSA and is expected to increase the likelihood that operators will find and respond to safety conditions more quickly. (3) Require Assessments of Pipelines That Are Not Already Covered Under the IM Program Requirements at Least Once Every 10 Years PHMSA is requiring that operators periodically assess onshore, piggable, hazardous liquid pipeline segments in non-HCAs. PHMSA has determined that expanding assessment requirements to these non-HCA pipeline segments will provide operators with valuable information they may not have collected if regulations were not in place. Such a requirement works to ensure prompt detection and remediation of corrosion and other deformation anomalies across the Nation, not just in populated or environmentally sensitive areas as defined by Federal regulations. There is still considerable consequence risk— regarding personal safety, environmental damage, and economic impact—of a spill in less-populated areas, into waterways not designated as ‘‘commercially navigable,’’ recreational areas, commercial fishing areas, and agriculturally productive areas that do not meet the definition of an HCA. In this rulemaking, § 195.416 requires operators to assess onshore, piggable, non-HCA, hazardous liquid pipeline segments at least once every 10 years, which allows operators to prioritize assessments in HCAs over assessments in non-HCAs (the assessment period is 5 years for hazardous liquid pipeline segments that are in or can otherwise affect an HCA). The individuals who review the results of these assessments will need to be qualified by knowledge, PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 52269 training, and experience and will be required to consider any uncertainty in the results obtained, including ILI tool tolerance, when determining whether any conditions could adversely affect the safe operation of a pipeline. Such determinations will have to be made promptly, but no later than 180 days after an inspection, unless the operator demonstrates that the 180-day deadline is impracticable. Operators are required to comply with the other provisions in part 195 in implementing the requirements in § 195.416. That includes having appropriate provisions for performing these periodic assessments and any resulting repairs in an operator’s procedural manual (see § 195.402); adhering to the recordkeeping provisions for inspections, tests, and repairs (see § 195.404); and taking appropriate remedial action under § 195.401(b)(1), as discussed below. Such requirements will help ensure operators obtain information necessary for the detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Of the many assessment methods, PHMSA has found that ILI in many cases is the most efficient and effective. Operators can perform ILIs while pipelines are in service without any interruption of product flow. Further, ILIs are non-destructive and can provide information beyond direct assessments, which can only tell whether there is exterior coating damage or corrosion, and hydrotests, which are essentially ‘‘pass’’ or ‘‘fail.’’ ILI tools, which are constantly improving, can provide accurate information on internal corrosion, external corrosion, cracks, and gouges. Additionally, there is robust guidance and documentation for the use of ILI; API and the National Association of Corrosion Engineers (NACE) have developed standards for ILIs that provide guidelines on appropriate tool selection, assessment procedures, and the qualification of personnel conducting assessments. Currently, operators said they are performing ILI assessments on a large portion of both HCA and non-HCA pipeline mileage, even though no regulation requires them to assess mileage outside of HCAs. Reported repairs in non-HCA segments reflect this indication. PHMSA wants to best ensure that current assessment rates continue and expand to those areas not voluntarily assessed. PHMSA has determined that by adopting these amendments to the existing pipeline safety regulations, data collection will continue to improve across the entire pipeline system, and anomalies that E:\FR\FM\01OCR3.SGM 01OCR3 52270 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 may have previously gone undetected in non-HCAs will be detected and repaired in a more consistent manner. (4) Expand the Use of Leak Detection Systems for Certain Hazardous Liquid Pipelines With respect to new hazardous liquid pipelines, PHMSA is amending § 195.134 to require that all new covered pipelines, in both HCAs and non-HCAs, have leak detection systems within 1 year after this final rule is published in the Federal Register, and all covered pipelines constructed prior to the rule’s publication have leak detection systems within 5 years after this rule is published. Recent pipeline accidents, including related failures that occurred in 2010 on a crude oil pipeline in Salt Lake City, UT; a failure of another crude oil pipeline in Santa Barbara, CA, in 2015; a crude oil release in Belfield, ND, in 2016; and the failure of refined products lines in Dono Ana County, NM, in 2018, corroborate the significance of having an adequate means for identifying leaks in all locations along the pipeline right-ofway. PHMSA, aware of the significance of leak detection, held a 2-day workshop in Rockville, MD, on March 27–28 of 2012.33 These workshops sought comment from the public concerning many of the issues raised in the 2010 ANPRM, including leak detection expansion. Both workshops were well attended, and PHMSA received valuable input from stakeholders on the technical gaps and challenges for future research and ways to leverage resources to achieve common objectives and reduce duplication of research programs. Participants also discussed the development of leak detection for all pipeline types and the capabilities and limitations of current leak detection technologies. With respect to existing pipelines, part 195 currently contains mandatory leak detection requirements for only those hazardous liquid pipelines that could affect an HCA. Congress included additional requirements for leak detection systems in section 8 of the 2011 Pipeline Safety Act. That legislation requires the Secretary to submit a report to Congress, within 1 year of the enactment date, on the use of leak detection systems, including an analysis of the technical limitations and the practicability, safety benefits, and adverse consequences of establishing additional standards for the use of those systems. Congress authorized the issuance of regulations for leak 33 https://primis.phmsa.dot.gov/meetings/ MtgHome.mtg?mtg=75. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 detection if warranted by the findings of the report. PHMSA publicly provided the results of the 2012 Kiefner and Associates study on leak detection systems in the pipeline industry, including the current state of technology. The study found that most leak detection technologies can be retrofitted to existing pipelines, though many operators ‘‘fear investing in leak detection systems, with potentially little benefit to show from them and no way to truly measure success in a standardized way,’’ resulting in leak detection being implemented ‘‘cautiously, and incrementally, on measurement and other systems that are already in place.’’ 34 Based on information available to PHMSA, including post-accident reviews and the Kiefner Report, the need to expand the use of leak detection systems and strengthen the current leak detection requirements is clear. A robust leak detection system is extremely important to hazardous liquid operators because it triggers all other impact mitigation measures that an operator should plan for, including safe flow shutdown, spill containment, cleanup, and remediation. In this final rule, PHMSA is modifying § 195.444 to require a means for detecting leaks on all portions of a hazardous liquid pipeline system, including non-HCA lines, and to require that operators perform an evaluation to determine what kinds of systems must be installed to adequately protect the public, property, and the environment. The factors that must be considered during that evaluation include (but are not limited to) the characteristics and history of the affected pipeline, the capabilities of available leak detection systems, and the location of emergency response personnel. PHMSA is retaining the requirements in §§ 195.134 and 195.444 that each new computational leak detection system comply with the applicable requirements in API Recommended Practice 1130.35 Given the difficulties identified in the Kiefner study related to leak detection performance standards, PHMSA is not making any additional changes to the regulations concerning specific leak 34 Kiefner and Associates, Inc., ‘‘Final Report on Leak Detection Study-DTPH56–11–D–000001,’’ December 10, 2012; https://www.phmsa.dot.gov/ staticfiles/PHMSA/DownloadableFiles/Files/ Press%20Release%20Files/ Leak%20Detection%20Study.pdf. 35 API RP 1130 focuses on the design, implementation, testing and operation of Computational Pipeline Monitoring (CPM) systems that use an algorithmic approach to detect hydraulic anomalies in pipeline operating parameters for hazardous liquid pipelines. PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 detection system performance criteria requirements at this time. PHMSA will be studying this issue further and may make proposals concerning this topic in a later rulemaking. (5) Increase Accommodation of In-Line Inspection Tools In this final rule, PHMSA is amending the part 195 regulations to require that all hazardous liquid pipelines in HCAs and areas that could affect an HCA be made capable of accommodating ILI tools within 20 years, unless subject to PHMSA approval, the basic construction of a pipeline will not accommodate the passage of such a device or the operator determines it would abandon the pipeline because of the cost of complying with the amendment. Per the petition process at § 190.9, operators would be required to document these determinations and submit the documentation to PHMSA for approval. Modern ILI tools can provide a relatively complete examination of the entire length of a pipeline, including information about threats that other assessment methods cannot always identify. ILI tools also provide superior information about incipient flaws (i.e., flaws that are not yet a threat to pipeline integrity, but that could become so in the future), thereby allowing these conditions to be monitored over consecutive inspections and remediated before a pipeline failure occurs. Hydrostatic pressure testing, another well-recognized method, reveals flaws (such as wall loss and cracking flaws) that cause pipe failures at pressures that exceed actual operating conditions, but only allows operators to determine whether a required safety margin is met (i.e., pass/fail) and does not provide information about the existence of anomalies that could deteriorate over time between tests. Similarly, external corrosion direct assessment (ECDA) is a form of direct assessment that can identify instances where coating damage or ineffective coatings may be affecting pipeline integrity, but operators must perform additional activities, including follow-up excavations and direct examinations, to verify the extent of that threat. ECDA also does not provide information about the internal condition of a pipe to the extent an ILI tool would. The current regulations for the passage of ILI devices in hazardous liquid pipelines are prescribed in § 195.120, which require that new and replaced pipelines are designed to accommodate ILI tools. The basis for these requirements is a 1988 law that addressed the Secretary’s authority with regard to requiring the accommodation E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations of ILI tools. This law required the Secretary to establish minimum Federal safety standards for the use of ILI tools, but only in newly constructed and replaced hazardous liquid pipelines (Pub. L. 100–561). As the Research and Special Programs Administration (RSPA; a predecessor agency of PHMSA), explained in the final rule published on April 12, 1994 (59 FR 17275), that promulgated § 195.120, ‘‘the clear intent of th[at] congressional mandate [wa]s to improve an existing pipeline’s piggability,’’ and to ‘‘require the gradual elimination of restrictions in existing hazardous liquid and carbon dioxide lines in a manner that will eventually make the lines piggable.’’ RSPA also noted that Congress amended the 1988 law in the Pipeline Safety Act of 1992 (Pub. L. 102–508) to require the periodic internal inspection of hazardous liquid pipelines, including with ILI tools in appropriate circumstances. In 1996, Congress passed another law further expanding the Secretary’s authority to require pipeline operators to have systems that can accommodate ILI tools. In particular, Congress provided additional authority for the Secretary to require the modification of existing pipelines whose basic construction would accommodate an ILI tool to accommodate such a tool and permit internal inspection (Pub. L. 104–304). RSPA established requirements for the use of ILI tools in pipelines that could affect HCAs in a final rule published on December 1, 2000 (65 FR 75378). Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the requirements for the passage of ILI tools to be extended to existing hazardous liquid pipeline facilities, provided the basic construction of those facilities can be modified to permit the use of smart pigs. The current requirements apply only to new hazardous liquid pipelines and to line sections where the line pipe, valves, fittings, or other components are replaced. Exceptions are also provided for certain kinds of pipeline facilities, including manifolds, piping at stations and storage facilities, piping of a size that cannot be inspected with a commercially available ILI tool, and smaller-diameter offshore pipelines. In this final rule, PHMSA is taking steps to further facilitate the gradual elimination of pipelines that are not capable of accommodating smart pigs in accordance with the authority provided in section 60102(f)(1)(B). PHMSA is limiting the circumstances where a pipeline can be constructed without being able to accommodate a smart pig. Under the current regulation, an operator can petition the PHMSA VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 Administrator for such an allowance for reasons of impracticability, emergencies, construction time constraints, costs, and other unforeseen construction problems. PHMSA believes that an exception should still be available for emergencies and where the basic existing construction of a pipeline makes that accommodation impracticable. Regulations already require that new and replaced pipelines accommodate ILI tools, and many of the pipelines covered by this new rule will need to be replaced and therefore will accommodate ILI tools before the end of the 20-year implementation period. Providing industry with sufficient time to implement this provision allows the industry to prioritize retrofits and replacements based on age or other factors; it also reduces the mileage of pipeline potentially needing to be replaced before it has reached the limit of its operational life. PHMSA determined that the 20-year timeline strikes the appropriate balance between the need for upgrades with the operational challenges of making these changes. (6) Clarify Other Requirements In this final rule, PHMSA is also making several other clarifying changes to the regulations that are intended to improve compliance and enforcement. First, PHMSA is proposing to revise paragraph (b)(1) of § 195.452 to better harmonize this section with other parts of the current regulations. Currently, § 195.452(b)(2) requires that segments of new pipelines that could affect HCAs be identified before the pipeline begins operations, and § 195.452(d)(1) requires that baseline assessments for covered segments of new pipelines be completed by the date the pipeline begins operation. However, § 195.452(b)(1) does not require an operator to draft its IM program for a new pipeline until 1 year after the pipeline begins operation. These provisions are inconsistent, as the identification of could-affect segments and performance of baseline assessments are elements of the written IM program. PHMSA is amending the table in (b)(1) to resolve this issue by eliminating the 1-year compliance deadline for Category 3 pipelines. An operator of a new pipeline is required to develop its written IM program before the pipeline begins operation—there is no burden associated with this amendment because operators already were required to report to DOT prior to construction. Second, as mentioned in the non-HCA assessment section, operators of both HCA lines and non-HCA lines will have PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 52271 equal requirements for the ‘‘discovery’’ of conditions, which occurs when an operator has adequate information about a condition to determine that it presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. This could include demonstrating why such information would not be available prior to that date. If an operator believes that unique circumstances exist in a particular case that make the 180-day period impracticable, the operator must submit a notification to PHMSA and provide an expected date when adequate information will become available. The submission of such a notification, by itself, will not affect compliance determinations on whether the 180-day requirement was met. PHMSA is thereby amending the existing ‘‘discovery of condition’’ language at § 195.452(h)(2) in the pipeline safety regulations to reflect these changes. A decade’s worth of IM inspection experience has shown that many operators are performing inadequate information analyses (i.e., they are collecting information but are not affording it sufficient consideration, or they are not promptly evaluating the information they have gathered following events that have increased risk, such as historic weather events). Ongoing data integration is one of the most important aspects of the IM program, and operators must account for interactions between threats or conditions affecting the pipeline when setting priorities for dealing with identified issues. For example, evidence of potential corrosion in an area with foreign pipeline crossings,36 nearby current interference from power lines and electrically powered transport systems, evidence of land movement or waterway channel changes that may impact pipeline integrity, and recent aerial patrol indications of excavation activity could indicate a priority for operators to reassess risk and make timely changes to their IM program to reduce that risk. Consideration of each of these factors individually would not necessarily reveal any need for priority attention. PHMSA is concerned that a major benefit to pipeline safety intended in the IM rule is not being realized 36 Foreign pipelines can include other hazardous liquid, natural gas, water, sewer, or drainage pipelines. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 52272 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations because of inadequate information analyses. For this reason, PHMSA is adding specificity to paragraph (g) by establishing several pipeline attributes that must be included in these analyses and requiring explicitly that operators integrate analyzed information. PHMSA is also requiring operators to consider explicitly any spatial relationships among anomalous information. PHMSA supports the use of computer-based geographic information systems (GIS) to record this information. GIS systems can be beneficial in identifying spatial relationships, but analysis is required to identify where these relationships could result in situations adverse to pipeline integrity. Second, PHMSA is requiring operators to verify their pipeline segment identification (as HCAs or otherwise) annually by determining whether factors considered in their analysis have changed. Section 195.452(b) currently requires that operators identify each segment of their pipeline that could affect an HCA in the event of a release, but there is no explicit requirement that operators assure that their identification of covered segments remains current. As time goes by, the likelihood increases that factors considered in the original identification of covered segments may have changed. Construction activities or erosion near the pipeline could change local topography in a way that could cause product released in an accident to travel farther than initially analyzed. Changes in agricultural land use could also affect an operator’s analysis of the distance released product could be expected to travel. Changes in the deployment of emergency response personnel could increase the time required to respond to a release and result in a release affecting a larger area if the original segment identification relied on emergency response in limiting the transport of released product. Therefore, PHMSA has determined that operators should periodically re-visit their initial analyses to determine whether they need updating; operators might identify new HCAs in subsequent analyses. The change that PHMSA is adopting does not automatically require operators to re-perform their segment analyses. Rather, it requires operators to first identify the factors considered in their original analyses, determine whether those factors have changed, and consider whether any such change would likely affect the results of the original segment identification. If so, the operator is required to perform a new segment analysis to validate or change VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 the endpoints of the segments affected by the change. Further, Section 29 of the 2011 Pipeline Safety Act states that ‘‘[i]n identifying and evaluating all potential threats to each pipeline segment pursuant to parts 192 and 195 of title 49, Code of Federal Regulations, an operator of a pipeline facility shall consider the seismicity of the area.’’ While seismicity is already mentioned at several points in the IM program guidance provided in Appendix C of 49 CFR part 195, PHMSA is amending the PSR to further comply with Congress’s directive by including an explicit reference to seismicity in the list of risk factors that must be considered in establishing assessment schedules (§ 195.452(e)), performing information analyses (§ 195.452(g)), and implementing preventive and mitigative measures (§ 195.452(i)) under the IM requirements. Finally, the PIPES Act of 2016 contained two sections PHMSA identified as self-executing and that PHMSA could incorporate into the PSR without notice of public comment or previous proposed rulemaking. Section 14 of the PIPES Act of 2016 requires operators of hazardous liquid pipeline facilities to provide safety data sheets to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. Section 25 of the PIPES Act of 2016 requires operators of underwater hazardous liquid pipeline facilities in HCAs that are not offshore pipeline facilities and that any portion of which are located at depths greater than 150 feet below the surface of the water to complete ILI assessments appropriate to the integrity threats specific to those pipelines no less frequently than once every 12 months. Furthermore, section 25 of the PIPES Act of 2016 requires that operators use pipeline route surveys, depth of cover surveys, pressure tests, ECDAs, or other technology that the operator demonstrates can further the understanding of the condition of the pipeline facility, as necessary to assess the integrity of those pipelines on a schedule based on the risk that the pipeline facility poses to the HCA in which the facility is located. PHMSA is amending the PSR by codifying the statutory language of these provisions. III. Liquid Pipeline Advisory Committee Recommendations The Liquid Pipeline Advisory Committee (LPAC) is a statutorily mandated advisory committee that advises PHMSA on proposed safety PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 standards, risk assessments, and safety policies for hazardous liquid pipelines. The Pipeline Advisory Committees (PAC) were established under the Federal Advisory Committee Act (Pub. L. 92–463, 5 U.S.C. App. 1–16) and the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). Each committee consists of 15 members, with membership divided among the Federal and State agencies, the regulated industry, and the public.37 The PACs advise PHMSA on the technical feasibility, practicability, and costeffectiveness of each proposed pipeline safety standard. On February 1, 2016, the LPAC met at the Hilton Arlington in Arlington, VA, to discuss this rulemaking. During the meeting, the LPAC considered the specific regulatory proposals of the NPRM and discussed various comments to the NPRM proposed by the pipeline industry, public interest groups, and government entities. To assist the LPAC in their deliberations, PHMSA presented a description and summary of the eight major issues in the NPRM and the comments received on those issues, as well as some sample regulatory text changes to foster discussion. During the meeting, eight votes were taken: One vote on each major topic of the NPRM. For each major topic of the rule, the LPAC came to a consensus decision that the provisions of the rulemaking would be technically feasible, reasonable, cost-effective, and practicable, provided PHMSA made certain changes. The order the topics were discussed in, the changes the committee agreed upon, and the corresponding vote counts were as follows: Gravity lines: In the NPRM, PHMSA proposed to subject gravity lines to reporting requirements for data gathering purposes, as there are currently no regulatory requirements for these lines and little data for potential regulatory decision-making purposes. The LPAC voted 9–1 that the NPRM, with respect to gravity lines, as published in the Federal Register, and the draft regulatory evaluation were technically feasible, reasonable, cost37 Members from the general public include two members who have education, background, or experience in environmental protection or public safety. At least one of the five members must have education, background, or experience in risk assessment and cost-benefit analysis. No public member can have a significant interest in the pipeline, petroleum, or gas industry. At least one of the public members must have no financial interests in the pipeline, petroleum, or natural gas industries. See section 12(d), ‘‘Liquid Pipeline Advisory Committee Charter—October 2018 to October 2020,’’ https://www.phmsa.dot.gov/sites/ phmsa.dot.gov/files/docs/standards-rulemaking/ pipeline/4396/lpac-charter-final-102418.pdf. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations effective, and practicable, if PHMSA made the following changes: Modify (shorten) the reporting form, require no National Pipeline Mapping System (NPMS) submissions, provide reporting exceptions for lower-risk pipelines (for example, intra-plant lines), allow a 1-year implementation period for annual reporting, and allow a 6-month implementation period for accident reporting. The LPAC agreed that PHMSA should modify the reporting forms to gather only the data necessary for PHMSA to determine whether these lines need to be regulated in the future. LPAC members representing the pipeline industry requested that PHMSA consider reporting exceptions for lowerrisk pipelines, such as intra-plant gravity lines. The same members also requested that any reporting requirements for gravity lines not include NPMS submissions, asserting that incorporating that data into a mapping system would be costly compared to the amount of risk these lines pose. LPAC members representing the public did not support these recommendations. They noted that as gravity line mileage is already limited, and the reporting requirement is only being used to gather data, excepting a subset of this limited mileage from reporting requirements would be counter-productive. Further, the public members strongly suggested that NPMS submissions be included for gravity lines, as location could be an important data point PHMSA could collect. Gathering lines: In the NPRM, PHMSA proposed to collect information on all gathering lines and subject regulated gathering lines to periodic assessment and leak detection requirements. Much of the LPAC’s discussion for gathering lines mirrored the topics discussed regarding gravity lines. During the discussion, PHMSA noted that under 49 U.S.C. 60132, only transmission-pipeline operators are required to submit mapping data for use in the NPMS. As a result, the LPAC removed language concerning NPMS submissions by gathering line operators. Ultimately, the committee voted 10–0 that the NPRM regarding gathering lines, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost effective, and practicable if PHMSA made the following changes: modify (shorten) the reporting form, allow a 1-year implementation period for annual reporting, and allow a 6-month implementation period for accident reporting. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 Leak detection: In the NPRM, PHMSA proposed that all hazardous liquid pipelines transporting liquid in single phase (without gas in the liquid) include a leak detection system and have it operate and maintained per specified standards. Many commenters noted that there was no implementation period for PHMSA’s proposed leak detection requirements. The LPAC proposed a 5-year implementation period for leak detection systems on existing lines and a 1-year implementation period for leak detection systems on new lines. The LPAC also recommended PHMSA not apply leak detection requirements to offshore gathering lines due to various technical challenges associated with flow monitoring and leak detecting. The LPAC voted unanimously that the NPRM, regarding leak detection, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost effective, and practicable if PHMSA made the following changes: Allow a 5-year implementation period for existing pipelines, allow a 1-year implementation period for new pipelines, and exempt offshore gathering lines from the leak detection requirements. Clarifying other requirements: In the NPRM, PHMSA proposed to revise the IM requirements to specify additional pipeline attributes for operators to analyze when evaluating the integrity of pipelines in HCAs; to require the integration of all sources of information, including spatial relationships, when determining pipeline integrity; to require operators have a written IM plan prior to a specific pipeline’s operation; and to require annual HCA segment identification and verification. During the meeting, the LPAC primarily discussed whether there should be a timeframe for implementing the specific data attributes and integrating all sources of information when determining pipeline integrity. Committee members representing the public argued that, because these provisions were clarifications of existing requirements, operators should have already been performing many of these actions, and an extended implementation period would not make sense. Several members who represented the public pushed for a 1-year implementation period. LPAC members representing the industry noted that developing data integration systems to a level that PHMSA would like could be expensive and timeconsuming, possibly taking several years. Further, LPAC members PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 52273 representing industry noted that while a lot of data integration is already occurring in operators’ IM programs, it could take some operators an extended period to adjust their software to incorporate all the items in PHMSA’s proposed list. LPAC members representing industry proposed PHMSA allow operators a 3-year deadline from the rule’s issuance to fully implement the proposed list of attributes. Ultimately, the LPAC voted 7–3 that the NPRM, regarding the data integration requirements, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable if operators begin implementing the requirements upon the rule’s issuance with a deadline of 3 years for full implementation. Inspections following extreme weather events: In the NPRM, PHMSA proposed requiring operators to perform inspections of pipelines that may have been affected by natural disasters or extreme weather events within 72 hours after the cessation of the event to better ensure that no conditions exist that could adversely affect the safe operation of that pipeline. The LPAC voted unanimously that the NPRM, as it relates to inspections following extreme weather events, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable, if PHMSA included the term ‘‘landslide’’ as a specific extreme weather event and qualify the term ‘‘other similar events’’ as it pertains to triggering the requirements of performing an inspection by tying the term to those events ‘‘that the operator determines to have a significant likelihood of damage to infrastructure.’’ Further, the LPAC recommended PHMSA clarify that the purpose of the inspection is to ‘‘detect conditions that could adversely affect the safe operation of the pipeline’’ and not ‘‘ensure that no conditions exist that could adversely affect the safe operation of the pipeline.’’ The LPAC also recommended PHMSA clarify that the inspection per these requirements would be an initial inspection, conducted within 72 hours of the area being safely accessible by personnel and equipment, to determine if any damage has occurred and whether additional assessments are necessary. Periodic assessments in non-HCAs: In the NPRM, PHMSA proposed to require operators to assess non-HCA pipelines at least once every 10 years using ILI or other equivalent methods. The LPAC agreed on this requirement and wanted to ensure it was not more restrictive than the requirement for assessing lines E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 52274 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations in HCAs. The LPAC voted unanimously that, regarding the provisions of the NPRM related to periodic assessments, the NPRM, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable if PHMSA ensured that the periodic assessment requirement applies to regulated pipelines that are not currently subject to the IM requirements at § 195.452, and made the methods operators use to assess nonHCA pipelines consistent with the methods operators use to assess HCA pipelines and allow operators to choose the appropriate tool for the appropriate threat. Making all pipelines in HCAs able to accommodate ILI tools: In the NPRM, PHMSA proposed to require all pipelines in HCAs be capable of accommodating ILI tools within 20 years. The LPAC voted 9–1 that, regarding the provision of the rule requiring the use of ILI tools in all HCAs, the NPRM, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable provided PHMSA insert a phrase stating that an operator can also file a petition if it determines it would abandon or otherwise shut down a pipeline because of the compliance cost of the provision. Repair criteria: In the NPRM, PHMSA proposed to make various changes to the existing repair criteria to reflect an improved prioritization of repairing abnormal pipeline conditions. The LPAC voted unanimously that, with regard to repair criteria for both HCA and non-HCA pipeline segments, the NPRM, as published in the Federal Register, and the draft regulatory evaluation are technically feasible, reasonable, cost-effective, and practicable if PHMSA considers allowing recognized engineering analyses to determine whether applicable dents and cracks are noninjurious and need no further investigation, and gives ‘‘full and equal consideration to the industry comments that were discussed [at the meeting].’’ 38 Those hazardous liquid industry comments provided at the LPAC meeting for PHMSA to consider were as follows: Repair Criteria for both HCA and nonHCA pipeline segments: 1. Regarding ‘‘Immediate’’ conditions: 38 At the Advisory Committee meeting, member Craig Pierson, representing the pipeline industry, submitted for the members’ consideration a written recommendation regarding repair criteria anomalies. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 a. Include crack anomalies greater than 70 percent of wall thickness or the tool’s maximum measurable depth if it is less than 70 percent; b. Remove specific references to ‘‘any indication’’ of significant stress corrosion cracking (SCC) and selective seam weld corrosion (SSWC). c. Allow for an industry recognized engineering analysis to determine those dents that are non-injurious and require no further investigation; and d. 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 MOP at the location of the anomaly, which should also include injurious cracks and SSWC. 2. Regarding 270-day conditions for HCAs and 18-month conditions for nonHCAs: a. Revise the existing reference to cracks and include crack anomalies greater than 50 percent of wall thickness or the tool’s maximum measurable depth if it is less than 50 percent; b. Allow for an industry recognized engineering analysis to determine those dents that are non-injurious and require no further investigation; and c. 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 MOP at the location of the anomaly. 3. Add a ‘‘Scheduled condition:’’ a. Anomalies that do not meet the 270-day or the 18-month repair criteria but have the possibility to grow before the next segment inspection are subject to predictive modeling of remaining strength; and b. Investigate in the years prior to the next inspection if the predicted burst pressure is less than 1.1 times the MOP at the location of the anomaly. In this final rule, PHMSA considered the recommendations of the LPAC and adopted them as PHMSA deemed appropriate. To summarize, the major changes PHMSA has made in this rule that deviate from the LPAC recommendations are as follows: (1) PHMSA has added an additional requirement that operators notify the appropriate PHMSA Region Director when they are unable to inspect infrastructure impacted by extreme weather within 72 hours; (2) PHMSA has removed the phrase ‘‘other similar event’’ from the extreme weather inspection requirements; (3) PHMSA has changed a word in the regulatory text for non-HCA assessments, to provide that operators must assess ‘‘line pipe’’ (instead of ‘‘pipelines defined PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 under § 195.1’’) not subject to the IM requirements at § 195.452; (4) PHMSA has restricted the non-HCA periodic assessment requirement to onshore, piggable, line pipe only, which removed the proposed assessment requirement for covered offshore lines and for regulated rural gathering lines; (5) PHMSA has removed the leak detection requirement for rural regulated gathering lines at § 195.11; and (6) PHMSA declined to move forward with the repair criteria and timelines as proposed for both HCAs and non-HCAs and has, instead, reverted to the existing non-IM repair language in § 195.401(b)(1) and the existing IM repair language at § 195.452(h). In the comments section, for each major topic of this final rule, PHMSA broadly discusses specific amendments proposed during the meeting and the corresponding discussion. PHMSA also discusses the instances where PHMSA did not adopt the specific recommendations of the LPAC. IV. Analysis of Comments and PHMSA Response On October 13, 2015, PHMSA published an NPRM (80 FR 61609) proposing several amendments to 49 CFR part 195. The NPRM proposed amendments addressing the following areas: (1) Reporting requirements for gravity lines. (2) Reporting requirements for gathering lines. (3) Inspections of pipelines following extreme weather events. (4) Periodic assessments of pipelines not subject to IM. (5) Repair criteria. (6) Expanded use of leak detection systems. (7) Increased use of in-line inspection tools. (8) Clarifying other requirements. Seventy organizations and individuals submitted comments in response to the NPRM, including public representatives, private citizens, industry service providers, individual pipeline operators, and trade associations representing pipeline operators. Some of the comments PHMSA received in response to the NPRM were comments beyond the scope or authority of the proposed regulations. The absence of amendments in this proceeding involving other pipeline safety issues (including several topics listed in the ANPRM) does not mean that PHMSA determined additional rules or amendments on other issues are not needed. Such issues may be the subject of other existing E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations rulemaking proceedings or future rulemaking proceedings. The remaining comments reflect a wide variety of views on the merits of particular sections of the NPRM. The substantive comments received on the NPRM are organized by topic below and are discussed in the appropriate section with PHMSA’s response and resolution to those comments. A. Reporting Requirements for Gravity Lines 1. PHMSA’s Proposal Gravity lines, pipelines that carry product by means of gravity, are currently exempt from PHMSA regulations. Many gravity lines are short and within tank farms or other pipeline facilities; however, some gravity lines are longer and can build up large amounts of pressure because they traverse areas with significant elevation changes, which could have significant consequences in the event of a release. For PHMSA to effectively analyze gravity line safety performance and risk, PHMSA needs basic data about those pipelines. PHMSA has the statutory authority to gather data for all pipelines (49 U.S.C. 60117(b)), and that authority was not affected by any of the provisions in the 2011 Pipeline Safety Act. Accordingly, PHMSA proposed to add § 195.1(a)(5) to require that the operators of all gravity lines comply with requirements for submitting annual, safety-related condition, and incident reports. jbell on DSK3GLQ082PROD with RULES3 2. Summary of Public Comment PHMSA received comments from trade organizations, citizen groups, and individuals on the scope and format of the reporting requirements. To reduce the reporting burden, industry representatives (API–AOPL, the GPA Midstream Association (GPA) and Energy Transfer Partners (ETP)) recommended that PHMSA create a new abbreviated annual report with input from operators to separate the reporting of pipeline data for regulated pipelines and those not currently subject to 49 CFR part 195. Specifically, API noted that pipelines not currently covered under part 195 (gravity lines) are not subject to operator qualification, control room management, leak detection, and HCA requirements, and therefore those areas should be excluded from reporting. The Texas Pipeline Association requested that reporting be limited to annual and incident reports, a suggestion also supported by the ETP. API–AOPL commented that industry experience indicates that the cost and time burdens associated with the VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 reporting requirements for gravity lines exceeded the cost estimate cited by PHMSA in the NPRM. The Environmental Defense Center requested that the reporting requirements include the location, operation, condition, and history of the pipelines, and multiple citizen groups requested that GIS mapping be required for pipelines. In addition to GIS mapping information, the Western Organization of Resource Councils and the Alliance for Great Lakes et al. recommended that PHMSA also require pipeline operators to meet minimum safety standards for all pipelines, a comment echoed by numerous other citizen groups and individuals. These commenters also requested that inspection reports, notices of violation, and similar documents be made readily available to the public. Trade organizations made additional comments regarding the applicability and implementation timeline for the reporting requirements. API–AOPL and other industry representatives requested that the data collection be narrowed, such that it would apply only to those gravity lines that could present a risk to the public, which: (1) Travel outside of facility boundaries for at least 1 mile, (2) operate at a specified minimum yield strength level of twenty percent or greater, and (3) are not otherwise exempted in § 195.1(b). On this same basis, Denbury Resources added a request to exempt CO2 pipelines. Finally, API–AOPL requested that PHMSA extend the proposed implementation period to 1 year after the effective date of the final rule. During the February 1, 2016, meeting, the LPAC recommended that PHMSA modify the NPRM to (1) require reporting from gravity pipeline operators using streamlined forms, (2) not require integration of gravity lines into NPMS, (3) provide exceptions for lower-risk pipelines (e.g., intra-plant lines), and (4) set a 1-year implementation period for the annual reporting requirement and a 6-month implementation period for the accident reporting requirement. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the scope and timing of the requirements for gravity lines. After considering these comments and LPAC input, PHMSA is modifying the exception for gravity lines at § 195.1 as it pertains to reporting requirements. This change will allow PHMSA to require operators of gravity lines to report information annually, starting 1 year from the rule’s effective date, and PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 52275 to report accidents and safety-related conditions starting 6 months from the rule’s effective date. PHMSA considers these deadlines practicable in view of the limited scope of the information requested for these lines. PHMSA focused collection on those data elements that will enable the agency to assess the risk posed by these lines and determine whether requirements that are more stringent are warranted in the future. To facilitate reporting and address commenters’ concerns about providing clear instructions on data elements that operators must fill out for gravity lines, PHMSA has modified its existing reporting form to provide clear instructions, including skip patterns, for relevant sections. In response to API’s specific suggestions regarding operator qualification, control room management, leak detection, and HCA reporting, these revisions exempted gravity lines from any fields that involve ‘‘Could Affect HCA’’ data. This targeting of the information collection request will reduce the burden associated with providing the information, as was requested by commenters. PHMSA recognizes that operators who are not currently submitting data will have to register with PHMSA to obtain an Operator Identification Number (OPID) under § 195.64, but the associated burden is minimal; PHMSA estimates that fewer than 10 operators would need to submit information for gravity lines. PHMSA estimates the total reporting burden at 66 hours per year, on average. During the LPAC meeting, the committee reached consensus on requiring gravity line operators to report safety-related conditions. These conditions could lead to significant consequences and are important data points for PHMSA to determine whether additional gravity line regulations may be necessary in the future. As explained previously, the purpose of the information collection is to support evaluation of the risk posed by gravity lines on the public. With this goal in mind, PHMSA is receptive to commenters who noted that pipelines located within the confines of a facility or in close proximity (within 1 mile) to a facility and do not cross a waterway currently used for commercial navigation pose a lower risk to the public and the environment. PHMSA has decided to exempt these lines from the reporting requirements. The language for this exception is similar to the language of an existing exception for low-stress pipelines at § 195.1. Further safety-related condition reporting exceptions at § 195.55(b) will help minimize the reporting burdens for E:\FR\FM\01OCR3.SGM 01OCR3 52276 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations operators. In the NPRM, PHMSA did not intend to propose requiring mapping of gravity lines at this time and therefore is finalizing the rule without this requirement. PHMSA understands commenters’ concerns that gravity line NPMS data submissions could be costly and burdensome. However, as PHMSA is not requiring these submissions as a part of this final rule’s reporting requirements, the cost and burden of these submissions were not and should not be considered as a part of the costbenefit analysis. If PHMSA determines, following analysis of the data received on gravity lines, that mapping of these lines or expanding reporting applicability to lines exempted in this final rule would be beneficial to improve public safety or protect the environment, it may consider additional requirements in a future rulemaking. Similarly, PHMSA is not requiring telephonic reporting of accidents involving gravity lines at this time but may reassess this requirement in a future rulemaking if analyses of the data suggest that doing so would enhance prevention, preparedness, and response to hazardous liquid releases from gravity lines. Comments relating to public reporting and the reporting of specific pipeline attributes discussed issues that PHMSA did not propose in the NPRM and are therefore out-of-scope and could not be considered for this rulemaking. Similarly, comments discussing minimum safety standards be applied to gravity lines were also out-of-scope because they requested more stringent requirements than what PHMSA proposed in the NPRM. jbell on DSK3GLQ082PROD with RULES3 B. Reporting Requirements for Gathering Lines 1. PHMSA’s Proposal In the NPRM, PHMSA also proposed to extend the reporting requirements of 49 CFR part 195 to all hazardous liquid gathering lines. Recent data indicates that PHMSA regulates less than 4,000 miles of the approximately 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States.39 That means that about 90 percent of the onshore gathering line mileage is not currently subject to any minimum Federal pipeline safety standards. Congress also ordered the review of existing State and Federal regulations for hazardous liquid gathering lines in the Pipeline Safety 39 GAO–12–388: ‘‘Pipeline Safety: Collecting Data and Sharing Information on Federally Unregulated Gathering Pipelines Could Help Enhance Safety,’’ March 2012, pg. 7; https://www.gao.gov/assets/590/ 589514.pdf. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 Act of 2011, to prepare a report on whether any of the existing exceptions for these lines should be modified or repealed, and to determine whether hazardous liquid gathering lines located offshore or in the inlets of the Gulf of Mexico should be subjected to the same safety standards as all other hazardous liquid gathering lines. Based on the study titled ‘‘Review of Existing Federal and State Regulations for Gas and Hazardous Liquid Gathering Lines’’ 40 that was performed by the Oak Ridge National Laboratory and published on May 8, 2015, PHMSA proposed additional regulations to help ensure the safety of hazardous liquid gathering lines. For PHMSA to effectively analyze safety performance and risk of gathering lines, we need basic data about those pipelines. PHMSA has statutory authority to gather data for all gathering lines (49 U.S.C. 60117(b)). Accordingly, PHMSA proposed to add § 195.1(a)(5) to require that the operators of all gathering lines (whether onshore, offshore, regulated, or unregulated) comply with requirements for submitting annual, safety-related condition, and incident reports. 2. Summary of Public Comment PHMSA received comments on hazardous liquid gathering lines that echoed those for gravity lines. Citizen groups and individuals again requested that the requirements for these lines include GIS mapping and minimum safety standards; that the reporting include location, operation, condition, and history; and that inspection reports, notices of violation, and similar documents be made available to the public. Trade organizations again commented on compliance costs and recommended that the reporting requirement be limited to annual and incident reports with an abbreviated form, have a phase-in implementation over 1 year, and exempt lower-risk pipelines. Specifically, API noted again that, as rural gathering lines are not subject to operator qualification, control room management, leak detection, and HCA requirements, those areas should be excluded from reporting. Trade organizations also made several additional recommendations related to the scope of applicability, the scope of requirements, and implementation. The Independent Petroleum Association of America (IPAA) commented that PHMSA exceeds its authority in requiring operators of gathering lines to 40 https://www.phmsa.dot.gov/staticfiles/PHMSA/ DownloadableFiles/Files/report_to_congress_on_ gathering_lines.pdf. PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 submit annual, safety-related condition, and incident reports. The GPA and other organizations noted that PHMSA did not fully account for the burden increase and cost of the reporting requirements for gathering lines in the preliminary RIA. The GPA recommended that information requested under § 195.61 and § 195.64 be excluded from data collection. Numerous trade organizations identified accident reporting for these lines as costly and duplicative. The Louisiana Mid-Continent Oil and Gas Association (LMOGA) commented that most, if not all accident information requested for gathering lines is already required to be reported under other existing Federal and State regulations, and the GPA recommended that information collected through an abbreviated Annual Report could be paired with Accident Reporting on Form F 7000–1 (rev 7–2014). LMOGA also recommended that mapping of gathering lines not be required because of incidental environmental impacts on wetlands, permitting, and resource costs for teams to enter wetlands and track these lines. The Offshore Operators Committee (OOC) requested that PHMSA make clear in the final rule that the agency’s intent is not to have the proposed reporting requirements apply to gathering lines offshore within State waters that are currently not regulated by PHMSA or the Bureau of Safety and Environmental Enforcement (BSEE) or to other gathering lines that are regulated by BSEE. Finally, commenters asked for implementation periods that ranged from 1 year (API–AOPL) to 10 years (Enterprise Products Partners) after the effective date of the rule. During the meeting on February 1, 2016, the LPAC recommended that PHMSA modify the NPRM to (1) require reporting from gathering pipeline operators using streamlined forms and (2) set a 1-year implementation period for the annual reporting requirement and a 6-month implementation period for the accident reporting requirement. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the scope and timing of the requirements for gathering lines. Regarding the comment that the proposed reporting requirement of § 195.1(a)(5) exceeds PHMSA’s statutory authority, PHMSA notes that the Federal Pipeline Safety Statutes state, in relevant part, ‘‘[t]he Secretary may require owners and operators of gathering lines to provide the Secretary E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations information pertinent to the Secretary’s ability to make a determination as to whether and to what extent to regulate gathering lines.’’ 49 U.S.C. 60117(b). PHMSA has determined that, in order to decide whether and to what extent to regulate gathering lines, as permitted by Congress, PHMSA requires pertinent information about those pipelines, including elements of the data contained in annual, safety-related condition, and incident reports. With this reporting requirement, PHMSA is not encroaching on the States’ regulatory authority, nor creating new jurisdiction. Rather, PHMSA is collecting pertinent information to determine if future regulation is necessary for the statutory purpose of promoting pipeline safety. More specifically, PHMSA is collecting items in the annual report that primarily include the mileage count for those gathering lines currently unregulated, the diameters of those lines, and whether they are operating at greater or less than 20 percent SMYS. The goal of collecting this specific information is to provide PHMSA with a better understanding of the scope of the Nation’s gathering pipeline infrastructure. As previously stated, recent data indicates PHMSA regulates only approximately 4,000 miles of the estimated 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States. That means that as much as 90 percent of the onshore gathering line mileage is not currently subject to any minimum Federal pipeline safety standards, and little is known about that mileage. In requiring accident reports for otherwise unregulated gathering lines, PHMSA is collecting data that includes the underlying cause for the accident, where the accident was located and how it was reported to the operator, and a value for any property damage caused. This data will be essential to understanding and managing risk. PHMSA uses information reported by pipeline operators to identify trends, provide performance measures, and understand the causes and consequences of pipeline incidents. Reporting requirements are in place for all pipelines except for the gravity and gathering pipelines addressed by this final rule. Each year, the U.S. Coast Guard’s National Response Center receives several notifications of hazardous liquid releases involving ‘‘gathering lines,’’ but details on these releases are not sufficient to understand the factors that contributed to the releases and the damages, or to evaluate whether the lines involved are gathering lines over which PHMSA has VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 jurisdiction.41 The reporting requirements for gathering lines will help PHMSA have a more complete understanding of the risks these lines may pose. PHMSA notes that one of its challenges is to understand and target risk, which requires a systematic approach to risk management, including a ‘‘comprehensive understanding of the factors contributing to risk and the ability to focus resources in those areas that pose the greatest risk.’’ One of PHMSA’s strategies for dealing with this challenge is to improve data collection and analysis, collect the right data to evaluate risks from unregulated entities, and improve the transparency of information and public awareness of pipeline and hazardous materials safety issues. The long-term benefits of having better information may include reducing incidents, enhancing incident response, and increasing public confidence. As such, PHMSA is finalizing the requirement for operators of gathering lines to report information annually, starting 1 year from the rule’s effective date, and to report accidents and safetyrelated conditions starting 6 months from the final rule’s effective date. PHMSA considers these deadlines practicable in view of the scope of the information requested. To facilitate reporting and address commenters’ concerns about providing clear instructions on data elements that must be filled out for gathering lines, PHMSA has modified its existing reporting form to provide clear instructions, including skip patterns, on the relevant sections that gathering line operators must fill out. In response to API’s specific suggestions regarding operator qualification, control room management, leak detection, and HCA reporting, these revisions exempted rural gathering lines from any fields that involve ‘‘Could Affect HCA’’ data. PHMSA recognizes that operators who are not currently submitting data will have to register for an identifier, but PHMSA expects the burden on operators to do this is small. In its analysis, PHMSA assumed that a majority of the reporting of currently unregulated gathering lines would be done by operators who already have OPIDs. PHMSA estimates that, at a minimum, approximately 20 operators will need to submit information for gathering lines for the first time, and another 56 operators will add information about gathering lines to 41 NRC data for 2010 through 2014 show 116 incidents categorized as ‘‘pipeline’’ incidents and that specifically include the term ‘‘gathering’’ in the incident description. Many more pipeline incidents could also be from gathering lines. PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 52277 their existing annual reports. PHMSA estimates the total reporting burden at 402 hours per year, on average. See the revised RIA accompanying the final rule for additional detail. Some commenters requested that PHMSA clarify whether these reporting requirements applied to offshore gathering lines in State waters. As the purpose of the information collection is to evaluate the public risk posed by gathering lines, PHMSA found it appropriate to extend the reporting requirements to certain offshore gathering lines in State waters. In its proposal, PHMSA did not intend to require mapping or NPMS submissions for gathering lines. Under 49 U.S.C. 60132, only transmission line operators are required to submit mapping data for use in the NPMS; PHMSA does not have the explicit authority to collect NPMS data for gathering lines. PHMSA is therefore finalizing the rule without imposing this requirement on operators of gathering lines. Similar to requirements for gravity lines, PHMSA is not requiring telephonic reporting of accidents involving gathering lines to PHMSA at this time since such a requirement would not support the purpose of this data collection effort, which is to enable PHMSA to evaluate risk over time for potential future action. PHMSA notes that operators must still report spills to the National Response Center and other relevant authorities. PHMSA will reassess the utility of requiring notification for incidents involving gathering lines in a future rulemaking if the analyses suggest that such notifications would enhance prevention, preparedness, and response to hazardous liquid releases from gathering lines. Certain commenters also stated their belief that PHMSA neglected to account for the costs and burden associated with the initial compiling of the data needed to complete the forms. In many cases, the commenters suggested, information may not have been recorded or may not have been provided during mergers or acquisitions. PHMSA noted in the RIA that it expects operators to have the requested information readily available, as it is essential for pipeline operation and safety. PHMSA allows operators to enter ‘‘unknown’’ when values cannot be determined for certain data fields. In the burden estimate, PHMSA allotted time for operators to compile the proper data and organize it into the requested format. See the RIA for further details. PHMSA did not impose minimum safety standards on currently unregulated gathering lines, as some E:\FR\FM\01OCR3.SGM 01OCR3 52278 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations commenters suggested, because the agency currently does not have data to analyze what risk, if any, those lines may pose to surrounding communities and environments. However, under these provisions, PHMSA will gather data on unregulated gathering lines and will use that data to determine whether additional safety regulations may be necessary. C. Pipelines Affected by Extreme Weather and Natural Disasters jbell on DSK3GLQ082PROD with RULES3 1. PHMSA’s Proposal Recent events demonstrate the importance of ensuring that our Nation’s waterways are adequately protected in the event of a natural disaster or extreme weather. PHMSA is aware that responsible operators might do such inspections; however, because it is not a requirement, some operators do not. Therefore, PHMSA proposed to require that operators perform an additional inspection within 72 hours after the cessation of an extreme weather event such as a hurricane or flood, an earthquake, a natural disaster, or other similar event. Specifically, PHMSA proposed that an operator must inspect all potentially affected pipeline facilities after an extreme weather event to help ensure that no conditions exist that could adversely affect the safe operation of that pipeline. The operator would be required to consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the inspection required. The initial inspection must occur within 72 hours after the cessation of the event, defined as the point in time when the affected area can be safely accessed by available personnel and equipment required to perform the inspection. Based on PHMSA’s experience and coordination with operators following natural disasters, PHMSA has found that 72 hours is reasonable and achievable in most cases. If an operator finds an adverse condition, the operator must take appropriate remedial action to best ensure the safe operation of a pipeline based on the information obtained as a result of performing the inspection. PHMSA specifically asked for comments on how operators currently respond to these events, what type of events are encountered, and if a 72-hour response time is reasonable. 2. Summary of Public Comment Some trade organizations recommended that certain requirements be eliminated altogether or consolidated VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 to reduce what they considered to be duplicative of existing emergency planning requirements in § 195.402(e)(4). Commenters were nearly unanimous in requesting that PHMSA clarify the definition of extreme weather event, the 72-hour timeline, and the timeline for mitigating or repairing anomalies. The GPA recommended that PHMSA either define exactly which events require response and inspection or establish performance expectations without partially defining the criteria, while the County of Santa Barbara recommended that the proposed regulations specify a threshold at which action would be required. Congresswoman Lois Capps (California) recommended that PHMSA include definitions and/or citations of existing definitions for qualifying events and the responsible party for such a determination. Congresswoman Capps also recommended that PHMSA clarify the terminology for an ‘‘appropriate method for performing the inspection’’ after the event. In addition to clarification of the definition of extreme weather event, trade groups also requested clarification of the 72-hour timeline following an extreme weather event, including how they would determine the cessation of the event, what appropriate action they would need to take following an event, and how to address the possibility of continued danger facing personnel or issues with availability of personnel and resources following an event. API–AOPL recommended that PHMSA define cessation as the point in time when no further threats to personnel safety or equipment exist in the affected area, allowing for safe access by pipeline personnel and equipment. They also recommended that the 72-hour window commence only once personnel and equipment could safely access the affected area. Citizen groups and individuals requested that operators be required to proactively address known risks and vulnerabilities in advance of an extreme weather event. For example, one organization recommended additional requirements to identify areas that are particularly vulnerable to extreme weather events or natural disasters, (e.g., stream crossings, and to develop proactive preventive measures.) The Alaska Wilderness League et al. recommended mandatory prevention measures that include shutting down pipeline operations in case of an imminent flood to prevent spills such as the 2011 Exxon Mobil Yellowstone River spill. Citizen groups also requested immediate reporting to PHMSA when remedial action is PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 required and that this information be made publicly available. The Environmental Defense Center requested that PHMSA provide specific, enforceable requirements for shutdown or other remedial action should an inspection reveal damage or anomalies, and that PHMSA clarify the type of events covered and the inspection methodology required. Finally, the OOC recommended that PHMSA coordinate with BSEE and the U.S. Coast Guard for activities that occur after hurricanes. During the meeting on February 1, 2016, the LPAC recommended that PHMSA modify the NPRM to (1) include landslides as an extreme weather event, (2) clarify that other similar events are those likely to damage infrastructure, and (3) require operators to inspect all potentially affected pipeline facilities to detect conditions that could adversely affect the safe operation of the pipeline. The LPAC also recommended that PHMSA modify the language regarding the inspection method to require operators to consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the initial inspection to determine damage and the need for additional assessments. Finally, the LPAC recommended that PHMSA clarify that the inspection must commence within 72 hours after the cessation of the event, which is defined as the point in time when the affected area can be safely accessed by the personnel and equipment, accounting for personnel and equipment availability. 3. PHMSA Response PHMSA disagrees with the comments stating the provisions at § 195.414 are unnecessary and duplicate operation and maintenance (O&M) manual requirements already contained in the response plan requirements under § 195.402. While § 195.402 does require that operators include certain ongoing monitoring measures in their O&M manuals, the proposed § 195.414 is much more specific in requiring that operators take appropriate remedial action to best ensure the safe operation of a pipeline based on the information obtained as a result of performing the post-event inspection required under paragraph (a) of this section. This will ensure that operators take the prescribed actions; having measures described in an operator’s O&M manual, as previously required, is not equivalent to action. PHMSA maintains that separate and more specific requirements are E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations warranted to best ensure public safety and environmental protection following extreme events. Additionally, PHMSA notes that reporting is coordinated with BSEE, the U.S. Coast Guard, and other agencies under existing notification procedures if the assessment determines there was a release involving their areas of responsibility. Both 49 CFR parts 194 and 195 require operators to report spills to the National Response Center. PHMSA appreciates the feedback provided by the commenters regarding the need for greater clarity in the definition of extreme events and natural disasters and expectations on the timing and scope of post-event inspections. In developing the requirements, PHMSA sought to balance being explicit regarding the types of events that could increase the risk of a release and therefore require inspections, with providing sufficient flexibility to account for diverse geographical and pipeline design factors. PHMSA recognizes that the language recommended by the LPAC is useful in striking this balance and adopted most its revisions in the final rule under §§ 195.414(a), (b), and (c). PHMSA is removing the language ‘‘other similar event’’ as PHMSA found the phrase to be vague and unnecessary to accomplish the goals of the provision but is maintaining the LPAC’s recommended language regarding the ‘‘likelihood to damage infrastructure.’’ Per the finalized requirement, operators must inspect all potentially affected pipeline facilities following extreme weather events or natural disasters with the likelihood of damaging infrastructure, such as named hurricanes or tropical storms; floods that exceed the highwater banks of rivers, shorelines or creeks; and landslides or earthquakes occurring within the area of a pipeline, in order to detect conditions that could adversely affect the safe operation of that pipeline. As discussed earlier in this document, the conditions that trigger this requirement are those that have the potential to cause river scour, soil subsidence, or earth movement, all of which can subject a pipeline to additional external loads and forces and cause the pipeline to fail. Pipeline operators are already required to understand and analyze the impact such weather events and natural disasters may have on their systems based the physical characteristics, operating conditions, location, and prior history of susceptible pipelines. PHMSA retained the remedial actions unchanged from the proposal. While PHMSA intends for operators to inspect pipelines as soon as possible after an event ends, PHMSA also agrees with VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 commenters that personnel safety is paramount. Accordingly, PHMSA clarified that the cessation of the event occurs as soon as it is safe for personnel and equipment to access the area. Operators are responsible for determining when each site is safe enough for entry. In response to commenters who sought greater flexibility in the timing of the inspections by leaving it up to the operators, PHMSA disagrees and maintains that setting clear and consistent timelines is essential to ensuring that all operators detect and address any issues promptly. The final rule does provide a fallback to operators who must delay the start of actions beyond this time due to availability of equipment, but these operators must notify the Regional Director. This addition to the LPAC-approved language allows operators to retain flexibility due to unavailable equipment, while ensuring accountability and prompt action. PHMSA considers 72 hours to be a reasonable period for mobilizing personnel and equipment following an event. In response to commenters who expressed concerns that inspections cannot be reasonably be completed within the 72-hour window, PHMSA notes that the proposal did not require completion of the inspections within 72 hours, and neither does the final rule; PHMSA recognizes that this needed to be clarified in the rule text and has done so in the final rule. The final rule accordingly describes the actions it expects operators to perform, starting within 72 hours after the cessation of the event. Recognizing that some actions will need to be site-specific, PHMSA provides flexibility to operators to determine the measures that are appropriate to the event, pipeline design, and circumstances. PHMSA is receptive to the recommendation that operators should take precautionary measures to minimize exposure in advance of and during an extreme event (e.g., reducing operating pressure or shutting down a pipeline), and notes that the current IM regulations require operators to know and understand risks to their system, which includes the threat of extreme events such as flooding or wind damage. To execute their IM programs and assessments on non-HCA lines as per this final rule, operators will need to have pipeline system information to address risks to their systems. Operators will use the information they have gathered on their entire pipeline system to monitor conditions and determine any anticipated risks to their pipelines, PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 52279 including extreme weather events. Given that the existing IM regulations require preventive and mitigative measures for HCAs, which often include river crossings, it is appropriate for this section to address post-natural disaster inspections for damage specifically. D. Periodic Assessment of Pipelines Not Subject to IM 1. PHMSA’s Proposal PHMSA proposed to require integrity assessments for pipeline segments in non-HCAs. PHMSA believes that expanded assessment of non-HCA pipeline segments areas will provide operators with valuable information they may not have collected if regulations were not in place; such a requirement would help ensure prompt detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Specifically, the proposed § 195.416 would require operators to assess non-HCA (non-IM) pipeline segments with an ILI tool at least once every 10 years, which allows operators to prioritize HCA assessments. PHMSA proposed to allow other assessment methods if an operator provides OPS with prior written notice that a pipeline is not capable of accommodating an ILI tool. Such alternative technologies would include hydrostatic pressure testing or appropriate forms of direct assessment. Although imposing the full set of IM requirements in § 195.452 on non-HCA pipeline segments was not proposed, operators would be required to comply with the other provisions in 49 CFR part 195 in implementing the requirements in § 195.416. That includes having appropriate provisions for performing periodic assessments and any resulting repairs in an operator’s procedural manual (see § 195.402); adhering to the recordkeeping provisions for inspections, tests, and repairs (see § 195.404); and taking appropriate remedial action under proposed § 195.422, which, based on the existing IM repair criteria at § 195.452(h), identified specific types of anomalies and the timeframes by which they must be remediated. Operators would also follow the requirements for ‘‘discovery of condition,’’ where the discovery of a condition occurs when an operator has adequate information to determine that a condition exists. The operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to determine whether the condition could adversely affect the safe operation of the pipeline, unless 180 days is impracticable as determined by E:\FR\FM\01OCR3.SGM 01OCR3 52280 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 PHMSA. PHMSA sought public comment on the alternatives it considered under this specific proposal and on quantifying these alternatives in the regulatory impact analysis. 2. Summary of Public Comment Trade organizations offered comments and language revisions on the methods and requirements included in the periodic assessments, implementation period, inspection intervals, and exemptions for lower risk pipelines. Enterprise Products Partners requested that operators be afforded the latitude they have under current IM regulations to determine the actual threats to pipeline integrity present on a given segment and to tailor their integrity assessment program accordingly. For instance, Enterprise suggested that PHMSA revise the proposal to clarify that a crack tool is not required for every ILI assessment, stating specifically that ‘‘an additional ILI crack tool is beneficial only when there is an identified threat to the pipeline segment that could result in cracks, such as cyclic fatigue. Yet PHMSA proposes to require a [crack tool] in all circumstances and on every pipeline segment.’’ Other trade organizations echoed this and requested that PHMSA incorporate alternatives to ILI tools for periodic assessments into the rule. Trade organizations also recommended that PHMSA ensure the rule is consistent with existing IM rules, including the reassessment intervals and implementation period. The Texas Pipeline Association requested that reassessment intervals be based on sound engineering judgement and industry consensus standards. Finally, trade organizations recommend that PHMSA limit and specify the type of pipelines to which the requirement would apply, with some commenters requesting specific exemptions for short lines and CO2 pipelines. API–AOPL requested that PHMSA clarify that operators would not need to run assessments on idle or out-of-service pipelines. API–AOPL also requested that PHMSA clarify that it intends for the requirements to include transmission lines only. Finally, the GPA requested that PHMSA rely on American Society of Nondestructive Testing (ASNT) ILI PQ as the standard for data analysis rather than the current language ‘‘qualified by knowledge, training, and experience.’’ The GPA submitted additional comments to PHMSA on March 24, 2016, expressing concerns that PHMSA misrepresented aspects of this proposal during the LPAC meeting. In the LPAC meeting the GPA claimed that PHMSA asserted that VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 currently regulated gathering lines are subject to assessments; the GPA believes that this statement was inaccurate and led to a vote by the committee that was not based on accurate facts. Further, the GPA suggested that ‘‘it is possible there are gathering lines in non-rural areas which do not meet the Census Bureau definitions for high or other population areas. Thus, when properly applying the regulations as currently written, there are gathering lines, which are regulated by PHMSA and its state partners for safety purposes that are not subject to periodic assessments.’’ Trade organizations also commented on the cost of expanding requirements for pipelines located outside of HCAs. The Texas Pipeline Association commented that raising the level of regulation on facilities outside of HCAs will redirect resources from high-risk areas to lower-risk areas. They requested that PHMSA consider the costs to operators of the proposed changes related to facilities outside of HCAs. The OOC also commented that offshore lines present unique challenges that make them ill-fitted for ILI technology and hydrotests. Other groups and individuals commented on the methods and requirements included in the periodic assessments, inspection intervals, and additional requirements. A 5-year inspection interval was generally favored by citizen groups and individuals, including the Alliance for Great Lakes Et al. Congresswoman Capps highlighted that a 3-year interval between inspections had proven to be inadequate to detect corrosion that caused the Plains All American oil pipeline rupture in May 2015. These commenters also requested clarification that alternative methods of assessment must account for inspection along the entire pipeline both inside and outside HCAs and expressed concern with waivers for ILI tools or the use of direct assessment. The NTSB requested that PHMSA harmonize the gas and liquid regulations to the maximum extent practicable and cautioned that direct assessment is an ineffective alternative technology for IM when applying the 10-year assessment requirement for the integrity of an entire pipeline. They recommended that the IM program encompass a broad range of available IM technologies including, but not limited to, ILI, magnetic flux leakage, ultrasonic testing, and tests directed at determining the integrity of the pipe coating. Finally, some citizen groups and individuals requested that inspection reports be made publicly available and PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 that operators be required to submit primary inspection results and data to PHMSA. The Environmental Defense Center recommended third-party verification of inspection reports based on corrosion underreporting. These groups also requested risk assessment on non-IM pipelines and annual inspections for all federally regulated hazardous liquid pipelines. During the February 1, 2016, meeting, the LPAC recommended PHMSA modify the NPRM to clarify its application to pipelines regulated under § 195.1 that are not subject to the IM requirements in § 195.452. The LPAC also made additional language recommendations to clarify the method of the assessment when ILI tools are impracticable, including pressure tests, external corrosion direct assessment, or other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. 3. PHMSA Response PHMSA appreciates the information provided by the commenters. PHMSA notes that the LPAC, with minor tweaks, found the provision for requiring operators to perform these periodic assessments on all covered pipelines not subject to the integrity management requirements under § 195.452 to be a cost-effective, practicable, and technically feasible provision. However, several commenters noted challenges and cost-benefit concerns with assessing offshore lines and regulated rural gathering lines as a part of this proposal. In this final rule, PHMSA is limiting the assessment requirement to onshore, non-HCA, nongathering lines that can accommodate inline inspection tools. Under the current regulations, PHMSA notes that approximately 45 percent of hazardous liquid pipelines are required to be assessed per the IM requirements by being located within an HCA or because they can affect an HCA. PHMSA has determined that, through this provision, most onshore non-HCA mileage will be assessed at a consistent rate. Further, as pipeline operators continue to replace pipe through modernization projects and repairs, PHMSA assumes that virtually all the Nation’s pipeline mileage will be piggable within the next few decades. In the NPRM, PHMSA did not intend for the requirements applicable to lines outside of HCAs to be more stringent than those applicable to lines in HCAs. PHMSA agreed with the commenters and the LPAC that it is appropriate to provide the same flexibility for the assessment of lines outside of HCAs as E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations lines within HCAs, but PHMSA notes that many of these concerns appeared to be in response to PHMSA’s requirement to assess all non-HCA lines, even ones that were not readily piggable. As discussed above, this final rule’s nonHCA assessment requirement now applies to piggable, onshore transmission line only. This final rule does allow operators to use pressure testing, direct assessment, or other technology in cases when in-line inspections are impracticable. PHMSA has determined that ILI tools may not be available for all pipe diameters and threats being assessed, and providing operators the ability to use these other assessment methods on piggable lines is appropriate at this time. Further, per the comments received from commenters, including API and Enterprise, related to the use of crack tools, PHMSA has revised the final rule, at both §§ 195.416 and 195.452, to require crack tools only when there is an identified or probable risk or threat supporting their use. For example, if operators have identified a pipeline segment with identified or probable risks or threats related to corrosion and deformation anomalies, including dents, gouges, or grooves, then the operator must assess that segment with a tool capable of detecting those anomalies. Similarly, operators should assess pipeline segments with an identified or probable risk or threat related to cracks using a tool capable of detecting crack anomalies. Essentially, operators should always be selecting an appropriate assessment tool based on the pertinent threats to a given pipeline segment that have been identified by an operator’s risk assessment. An operator’s risk assessment should always be driving its integrity assessments and the integrity management program. An operator cannot properly maintain its pipeline if it does not know what threats to which the pipeline is susceptible to and which tools the company should be selecting to assess those threats. These threats can include, but are not limited to, pipe that may have manufacturing defects or have otherwise experienced in-service incidents. Under the existing requirements of § 195.452(c)(1) (after which PHMSA modeled the new assessment requirements in § 195.416), operators must select an assessment method capable of assessing seam integrity and of detecting corrosion and deformation anomalies if the applicable pipe is lowfrequency ERW pipe or lap-welded pipe susceptible to longitudinal seam failure. PHMSA has interpreted and intended the phrase ‘‘susceptible to seam failure’’ to apply to both low-frequency ERW VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 pipe and lap-welded pipe. In this final rule, PHMSA has expanded the assessment provisions to require operators to use a tool or tools capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies on lowfrequency ERW pipe, pipe with a seam factor less than 1.0 (as defined in § 195.106(e)) 42)), or lap-welded pipe susceptible to longitudinal seam failure. Certain stakeholders may interpret this requirement to mean that these tools will need to be run on every segment of low-frequency ERW pipe, pipe with a seam factor of less than 1.0, or lapwelded pipe. However, PHMSA only explicitly requires the use of these tools for segments of low-frequency ERW pipe, pipe with a seam factor less than 1.0, or lap-welded pipe when these types of pipe are determined by an operator to be susceptible to longitudinal seam failure based on excavation findings, examinations, leaks, failures, pressure tests, inline inspections, other operating history, and the manufacturing history of the pipe vintage and its history of seam leaks and failures. Similarly, PHMSA found that the proposed requirements for ‘‘discovery of condition’’ under § 195.416 were more stringent than the revisions proposed for § 195.452. To be consistent with the revised requirements under § 195.452 regarding the discovery of condition, the operator has 180 days to obtain sufficient information on conditions and make the required determinations, unless the operator can demonstrate that the 180-day timeframe is impracticable. In cases where an operator does not have adequate information within 180 days following an assessment, pipeline operators must notify PHMSA and provide an expected date when that information will become available. These revisions will provide consistency for the discovery of condition across all regulated HCA and non-HCA lines. PHMSA also agreed with the commenters and the LPAC that it is necessary to clarify which pipelines fall under the non-HCA assessment requirements. However, upon further review, PHMSA found that adopting the LPAC-recommended language for § 195.416(a), by clarifying application of this requirement to pipelines regulated under § 195.1 that are not subject to the IM requirements in § 195.452, would extend this requirement beyond 42 49 CFR 195.106(e) has seam factors for pipe seams that need to be de-rated for maximum operating pressure determination. A de-rated seam factor would be below 1.0 and include furnace lap welded and furnace butt welded pipe seams. PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 52281 PHMSA’s or the LPAC’s intent and would cover facilities not previously intended, such as pump stations. Therefore, instead of strictly adopting the language proposed by the LPAC, PHMSA is instead specifying that these requirements apply to onshore, piggable line pipe not covered under the IM requirements, including the relevant line pipe within pump stations, but not other appurtenances and components like metering stations, tanks, etc. Further, PHMSA is not requiring IM 5year assessments but is requiring operators to continue the implementation of the preventive and mitigative measures under IM (§ 195.452(i)) for appurtenances, pumps, tanks, etc., for these facilities that could affect a HCA. PHMSA believes this clarification captures the intent of the LPAC members. In response to the GPA’s suggestion for an alternative standard for data analysis, PHMSA’s existing process for data analysis has been through a rigorous rulemaking process. PHMSA is not incorporating alternative standards into this rule making that were not included at an earlier rulemaking stage and were not subject to public comment. Regarding the GPA’s other concern as to whether PHMSA provided the LPAC with inaccurate information concerning the extent to which operators are already required to perform assessments on gathering lines versus the new assessment requirements PHMSA was proposing in the NPRM, PHMSA notes that on pages 180 and 181 of the LPAC meeting transcript PHMSA clearly states that it is proposing subjecting currently regulated rural gathering lines to periodic assessment and repair requirements in §§ 195.416 and 195.422, saying, ‘‘When it comes to the gathering lines that we don’t currently regulate, [that] the regulations don’t currently address, the only requirements we’re applying will be the reporting requirements that we discussed prior. In the [NPRM], when it came to regulated rural gathering lines, we proposed to subject them to the assessment requirements in [§ 195.]416 and [§ 195.]422. There’s actually a proposal in the NPRM to link the two sections together, but it would not require that lines that are currently, today, not regulated to be assessed.’’ The statement by PHMSA at the LPAC meeting that the GPA questions states that regulated rural gathering lines have an assessment requirement in the NPRM as opposed to currently unregulated gathering lines, which do not. Further discussion and voting at the LPAC meeting indicated that the committee members fully E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 52282 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations understood PHMSA’s proposal, with committee members clarifying the definition by asking it to be revised to ‘‘transmission and regulated gathering lines’’ and noting ‘‘there’s clarity with this [definition] now.’’ Regarding the GPA’s other comment on the possibility of the existence of gathering lines in non-rural areas that are not assessed, PHMSA notes this is incorrect. Currently, the only regulated gathering lines that are not subject to assessment requirements are regulated rural gathering lines, which, per their name, are in rural areas. Under existing § 195.1(a)(4), any onshore gathering lines located in non-rural areas and gathering lines located in Gulf of Mexico inlets are covered by 49 CFR part 195, and if these gathering lines are within HCAs or could affect HCAs, they are subject to the full IM program requirements, including integrity assessments, under the current § 195.452. As defined in § 195.2, a ‘‘rural area’’ means ‘‘outside the limits of any incorporated or unincorporated city, town, village, or any other designated residential or commercial area such as a subdivision, a business or shopping center, or community development.’’ To exist outside of a ‘‘rural area’’ as that term is defined under § 195.2 (i.e., a ‘‘non-rural’’ pipeline), a pipeline would have to be inside (rather than outside) the limits of any incorporated or unincorporated city, town, etc. Per the definition of an HCA at § 195.450, a pipeline in such an area would be in an HCA, and therefore would be regulated and subject to assessment requirements. Therefore, with the exception of regulated rural gathering lines, operators should be assessing all other regulated gathering lines per their IM programs. PHMSA does not agree with API– AOPL that clarification is needed in the rule on the issue of ‘‘idle’’ pipelines. The Federal PSR list only two statuses for a pipeline: (1) In-service/active; or (2) ‘‘abandoned,’’ which the PSR defines as ‘‘permanently removed from service.’’ Although operators frequently refer to a pipeline that is not being actively used as ‘‘idle,’’ PHMSA has no current operational designation for an ‘‘idle’’ line. Unless they are abandoned in accordance with applicable procedures, pipelines that are not currently in use must meet all the requirements of the Federal PSR, including compliance with IM regulations if those pipelines are in HCAs. On March 17, 2014, a pipeline leaked crude oil into a highly populated suburb of Los Angeles, CA (Wilmington, CA), releasing an estimated 1,200 VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 gallons of oil.43 The pipeline was never purged and filled with inert material as per the operator’s procedures required by the regulations, and the operator (who bought the pipeline from another operator), believed the pipeline was ‘‘abandoned.’’ This demonstrates the fact that pipelines that have been ‘‘idled’’ can still present a safety risk and must be treated as active pipelines. Further, as operators can restart ‘‘idle’’ lines and transport product later, it is important that operators maintain these lines to the same level of safety and standards as an active, in-service line. Accordingly, PHMSA expects operators of ‘‘idle’’ lines to perform assessments and adhere to all the applicable regulations based on the line’s location. PHMSA considered the requests it received to make inspection reports for non-HCA lines publicly available and to require third-party inspection report verification. PHMSA determined that promulgating those requirements would make assessing non-HCA lines more burdensome than assessing HCA lines. Regarding requests that PHMSA require non-HCA inspections at 5-year intervals to ensure a larger number of populations and properties are protected, PHMSA notes that setting the non-HCA assessment interval to 5 years would make it equal to that for lines in HCAs. Lowering the non-HCA assessment period to any time below 5 years would make it more stringent than the requirement for HCAs and would not allow operators to prioritize those higher-consequence areas first. Similarly, requiring a yearly inspection of all hazardous liquid pipelines, as some commenters suggested, would be overly burdensome and would work against risk-based prioritization. Many commenters also requested that PHMSA require operators to perform risk assessments on non-IM pipelines. As discussed in the previous section on extreme weather events, PHMSA expects operators will need to have a certain amount of information on their HCA and non-HCA pipelines, including the environment in which they operate, for them to properly assess risk and the current condition of their pipeline system and to select the proper tool(s) for an adequate threat analysis. Operators cannot properly perform assessments if they do not know or understand the ‘‘as-is’’ state of their pipeline and any potential or actual threats. This information is required to comply with § 195.401(a), which states 43 Jeff Gottlieb: ‘‘Phillips 66 oil line in Wilmington blamed for 1,200-gallon spill,’’ Los Angeles Times, March 18, 2014. https:// articles.latimes.com/2014/mar/18/local/la-me0319-crude-oil-20140319. PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 that no operator may operate or maintain its pipeline systems at a level of safety lower than that required by subpart F of 49 CFR part 195 and the procedures it is required to establish under § 195.402(a). Therefore, PHMSA expects operators will already be performing a level of risk analysis on non-HCA lines as well as HCA lines. E. IM and Non-IM Repair Criteria 1.a PHMSA’s Proposal for § 195.452 (IM Repairs) In the NPRM, PHMSA proposed modifying criteria in § 195.452(h) for IM repairs to: • Categorize bottom-side dents with stress risers, pipe with significant stress corrosion cracking, and pipe with selective seam weld corrosion as immediate repair conditions; • Require immediate repairs whenever the calculated burst pressure is less than 1.1 times MOP; • Eliminate the 60-day and 180-day repair categories; and • Establish a new, consolidated 270day repair category. 1.b PHMSA’s Proposal for § 195.422 (Non-IM Repairs) PHMSA also proposed to amend the requirements in § 195.422 for performing non-IM repairs by: • Applying the criteria in the immediate repair category in § 195.452(h); and • Establishing an 18-month repair category for hazardous liquid pipelines that are not subject to IM requirements. 2. Summary of Public Comment Citizen groups and individuals expressed concern with the changes to the repair timeline categories. The Alliance for Great Lakes et al. requested that PHMSA maintain the 180-day repair timeframe for all repairs that are not classified as immediate, and the Pipeline Safety Trust (PST) did not see justification for the 18-month and ‘‘reasonable’’ time frames added for repairing pipelines outside of HCAs. API–AOPL requested a reasonable timeframe to address repairs in offshore pipelines that considers the type of repair and permit that might be involved. ETP recommended that PHMSA change the 270-day and 18month criteria to 1-year and 2-year criteria to assist operators with planning, budgeting, and scheduling. Enterprise Products Partners suggested specific language to clarify that § 195.422 would apply only to pipelines not subject to IM requirements in § 195.452 and those determined not to have the potential to affect HCAs. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations API–AOPL also expressed concern that PHMSA might apply these criteria beyond non-HCA transmission lines to gravity and gathering lines located offshore and recommended explicit language to state that § 195.422 does not apply to gravity or gathering lines. The GPA requested that PHMSA clarify the applicability of this section to out-ofservice, ‘‘idle’’ pipelines. Commenters also asked for additional standards for conditions triggering repairs. For example, one public safety organization requested a more stringent standard for the amount of metal loss that triggers ‘‘immediate repair,’’ whereas the Alliance for Great Lakes et al. recommended that PHMSA establish standards for the prevention, detection, and remediation of significant stress corrosion cracking and stress corrosion cracking. The IPAA commented that PHMSA did not address whether resources exist to make the additional repairs that would be required, nor did it demonstrate a nexus between existing risk and the more conservative repair requirements that justify the potential costs, especially when considering regulated gathering lines. The GPA requested documentation on the basis for requiring the same repair criteria for non-gathering lines as the repair criteria for pipelines affecting HCAs. Western Refining recommended that PHMSA exempt pipeline segments that normally operate at a low pressure from the pressure reduction requirement. API– AOPL recommended that PHMSA add an immediate repair condition for crack anomalies at a 70 percent nominal wall thickness and an 18-month repair condition on dents with corrosion. API– AOPL also recommended that PHMSA include a ‘‘Scheduled Conditions’’ repair condition for non-HCA lines, which would require an operator to make a report prior to the year when a calculation of the predicted remaining strength of the pipe (including allowances for growth and tool measurement error) shows a predicted burst pressure at less than 1.1 times the MOP at the location of the anomaly. This recommendation aimed to mitigate the potential for pressure-limiting, immediate features before the next ILI. Enterprise Products Partners recommended language to provide operators with flexibility to determine the severity of the reported metal loss indication and its potential impact on the integrity of the pipeline by setting the dent threshold as corroded areas deeper than 20 percent of the nominal wall thickness or where an engineering analysis indicates a reduction in the safe operating pressure of the dented area. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 API–AOPL and AGA recommended eliminating the SCC and SSWC immediate repair criteria. The AGA also requested that PHMSA allow pipeline operators to prioritize the repair of HCA segments over non-HCA segments. The GPA was also concerned that PHMSA’s definition of SCC was based on the use of the word ‘‘significant,’’ because the term is subjective and PHMSA’s proposed descriptors do not include all the variables that influence SCC behavior and is therefore very incomplete for assigning an ‘‘actionable’’ status for all instances. The PST requested that PHMSA change § 195.563(a) to require that constructed, relocated, replaced, or otherwise changed pipelines must have cathodic protection within 6 months instead of 1 year, and they also requested that PHMSA require operators to know what type of pipe is in the ground and set the MOP appropriately, or test the pipe with an appropriate hydrotest to demonstrate a safe MOP. During the meeting of February 1, 2016, the LPAC recommended that PHMSA modify the NPRM to include recognized industry engineering analysis regarding dents and cracks to determine they are non-injurious and do not require immediate repair, and to give full and equal consideration to the stakeholder comments that were considered during the LPAC discussion. 3. PHMSA Response PHMSA appreciates the information provided by the commenters. PHMSA proposed revisions to the IM repair criteria to provide operators greater flexibility regarding the repair timeframes for certain anomalies, provide additional clarification regarding specific anomaly types, and address pipe cracking issues both the agency and the NTSB had identified following the incident near Marshall, MI, especially regarding stress corrosion cracking and selective seam weld corrosion. PHMSA also proposed to apply these changes with some modifications to non-HCAs to provide flexibility to operators and allow the risk-based prioritization of repairs. PHMSA notes that the LPAC, with certain suggestions, found the changes to both the non-HCA repair criteria and the HCA repair criteria to be costeffective, practicable, and technically feasible provisions, and these provisions seemed to have wide stakeholder support following the ANPRM stage. However, PHMSA determined as part of the review process that it needs to gather additional data, including with respect to cost-benefit information, and to assess new technologies and practices PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 52283 before promulgating the proposed changes for non-HCA pipelines in this final rule. Based on this, PHMSA has decided to separate the repair-criteria provisions from this final rule and intends to issue a supplemental notice of proposed rulemaking where PHMSA would further analyze developing technology and practices, anomaly types and repair timeframes, and engineering critical assessment methods. This path will also provide commenters an additional opportunity to provide input on an important part of the regulations. PHMSA will incorporate any relevant discussion it would have included in this section of this rulemaking when discussing repair criteria in the supplemental notice. Therefore, for the purposes of this final rule, PHMSA is retaining the existing non-IM repair language at § 195.401(b)(1) and the existing IM repair language at § 195.452(h). For non-IM pipelines, §§ 195.401(b)(1), 195.585, and 195.587 outline the requirements for nonintegrity management pipeline repairs. Section 195.401(b)(1) requires operators that discover any condition that could adversely affect the safe operation of its pipeline system, they must correct the condition within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition. For IM pipelines, PHMSA expects operators to continue to follow the existing regulations in §§ 195.401(b)(2) and 195.452(h) as they are written and repair the listed anomaly types within the specified timeframes. F. Leak Detection Requirements 1. PHMSA’s Proposal With respect to new hazardous liquid pipelines, PHMSA proposed to amend § 195.134 to require that all new lines be designed to have leak detection systems, including pipelines located in non-HCA areas. With respect to existing pipelines, 49 CFR part 195 contains mandatory leak detection requirements for only those hazardous liquid pipelines that could affect an HCA. Congress included additional requirements for leak detection systems in section 8 of the 2011 Pipeline Safety Act. That legislation requires the Secretary to submit a report to Congress, within 1 year of the enactment date, on the use of leak detection systems, including an analysis of the technical limitations and the practicability, safety benefits, and E:\FR\FM\01OCR3.SGM 01OCR3 52284 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations adverse consequence of establishing additional standards for the use of those systems. Congress authorized the issuance of regulations for leak detection if warranted by the findings of the report. Based on information available to PHMSA including post-accident reviews and the Kiefner Report, PHMSA believes the need to strengthen the requirements for leak detection systems is clear. In addition to modifying § 195.444 to require a means for detecting leaks on all portions of a hazardous liquid pipeline system including non-HCA areas, PHMSA proposed that operators perform an evaluation to determine what kinds of systems must be installed to adequately protect the public, property, and the environment. The proposed amendment to § 195.11 extended these new leak detection requirements to regulated onshore gathering lines. jbell on DSK3GLQ082PROD with RULES3 2. Summary of Public Comment Trade organizations expressed concerns with requiring operators of gathering lines and certain nongathering lines to install and maintain leak detection systems. The GPA commented that PHMSA’s proposal is not appropriate for gathering lines at this time, citing findings of the ‘‘Liquids Gathering Pipelines: A Comprehensive Analysis’’ study,44 which concluded that (1) gathering lines present unique challenges to leak detection technologies; (2) gathering lines are constantly transition in flow, pressure, and line-packing; (3) benefits do not justify the cost for leak detection systems applied to gathering lines; and (4) there is a lack of demonstrated technology to reliably detect spills. The IPAA noted that PHMSA should not proceed with expanding leak detection systems because it had not performed an analysis of the practicability of establishing technically, operationally, and economically feasible standards for the capability of such systems to detect leaks, and the safety benefits and adverse consequences of requiring operators to use leak detection systems. The GPA also recommended that PHMSA provide relief for short sections of pipeline less than 1 mile in length and lines located within facilities where they pose no risk to the public. API– AOPL and OOC requested clarification that this section would not apply to offshore gathering lines. The commenters requested implementation 44 Energy and Environmental Research Center, University of North Dakota, 2015, https:// www.undeerc.org/bakken/pdfs/EERC%20Gathering %20Pipeline%20Study%20Final%20Dec15.pdf. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 periods ranging between 5 years (API– AOPL) and 7 years (GPA). Finally, the Texas Pipeline Association commented on the cost of complying with this regulation for lines outside of HCAs and the redirection of resources from highrisk areas to lower-risk areas that they allege would occur. Citizen groups and other commenters requested minimum standards for leak detection systems, and applicability to all hazardous liquids lines. The Pipeline Safety Coalition recommended the inclusion of (1) all existing hazardous liquids lines and all lines under construction at rulemaking; (2) prescriptive standards for leak detection classifications; (3) prescriptive standards for acceptable leak detection procedures and devices; and (4) standards that are specific to location, community, and environmentally sensitive areas. The Alliance for Great Lakes et al. commented that computational pipeline monitoring systems detect only large ruptures and involve significant data interpretation and analysis. They expressed concerns regarding the lack of system standards and guidance on how to assess the effectiveness of a given leak detection system on a given pipeline due to significant variations in pipeline design. The Environmental Defense Center also recommended that automatic shutdown systems be required. Beyond requirements for new pipelines, some commenters also requested a clear schedule for leak detection system for pipelines undergoing construction. For example, the NTSB urged PHMSA to include language that specifies a distinct trigger date for leak detection implementation on pipelines that have already started construction but would not yet be operational when the new regulation becomes effective. During the February 1, 2016, meeting, the LPAC recommended that PHMSA modify the NPRM to (1) provide a 5-year implementation period for existing pipelines and a 1-year implementation period for new pipelines and (2) clarify that the expanded use of leak detection systems is not applicable to offshore gathering pipelines. 3. PHMSA Response PHMSA notes that commenters asserting PHMSA lacks the authority to require leak detection systems because it did not first conduct a study of these systems are incorrect. PHMSA did perform a leak detection study (‘‘Leak Detection Study—DTPH56–11– PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 D000001’’ 45), as required by section 8 of the 2011 Pipeline Safety Act, and submitted this study to Congress on December 31, 2012. The study examined what methods and measures operators were using as leak detection systems and the limitations of those methods and measures. The study noted that ‘‘due to the vast mileage of pipelines throughout the Nation, it is important that dependable leak detection systems are used to promptly identify when a leak has occurred so that appropriate response actions are initiated quickly. The swiftness of these actions can help reduce the consequences of accidents or incidents to the public, environment, and property.’’ The study also noted that ‘‘incidents described as leaks can also have reported large release volumes.’’ Based on the results of the study, and due to pipeline accidents such as those near Marshall, MI, and Salt Lake City, UT, which the study referenced, PHMSA concluded that operators need to have an adequate means for identifying leaks to better protect the public, property, and the environment. PHMSA continues to foster leak detection technology improvements through research and development projects, and PHMSA is also considering pursuing rupture detection metrics in another rulemaking. Recognizing that leak detection technology can be unreliable does not imply that monitoring and leak detection are without value. The value of lost product, negative impacts to the environment, loss of pipeline functionality, spill remediation costs, and public perception all impact decisions regarding the implementation of leak detection systems. It is difficult to assign costs to many of these items. PHMSA expects that the implementation of leak detection systems on non-HCA pipelines will accelerate leak detection, lead to faster response and spill containment, and reduce damages from hazardous liquid releases. Given this information, PHMSA is finalizing a rule that requires all new and existing lines, except for gathering lines not subject to IM, regulated rural gathering lines, and offshore lines, to implement leak detection systems. Since all lines within HCAs are already subject to this requirement, the final rule affects pipelines outside of HCAs. 45 Kiefner & Associates, Inc.: ‘‘Leak Detection Study,’’ Final Report No. 12–173, DTPH56–11–D– 000001, December 10, 2012. https:// www.phmsa.dot.gov/staticfiles/PHMSA/ DownloadableFiles/Files/ Press%20Release%20Files/ Leak%20Detection%20Study.pdf. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations Commenters and LPAC members made persuasive arguments regarding the technical challenges that exist for implementing leak detection systems on offshore gathering lines due to the complex network of gathering lines coming from offshore platforms and tremendous fluctuations in flow controlled directly by production platforms. Further, commenters had concerns that there was not adequate justification for leak detection requirements on regulated rural gathering lines due to the lack of incident history. PHMSA did not receive any data or comments that contradicted these assertions; therefore, PHMSA is not extending leak detection requirements to offshore gathering lines or regulated rural gathering lines at this time. However, PHMSA does note that the LPAC had no objections to extending this requirement to regulated rural gathering lines and found the provision to be a cost-effective, practicable, and technically feasible provision. Further, during the 12866 meeting between OIRA and API on December 12, 2016, API presented data stating that operators agree with PHMSA’s assumptions regarding the use of leak detection systems on non-HCA pipelines. As such, PHMSA may consider extending leak detection requirements to these lines in the future. PHMSA considered input from the comments and from the LPAC in setting compliance periods of 1 year for all new lines, and 5 years for all existing lines. Regarding concerns about compliance periods for pipelines under construction, PHMSA considers any line that becomes operational after the publication of this rule to be a new line and will have 1 year to comply. PHMSA will consider pipelines that are already operational before the publication of this rule as existing lines, and those will have 5 years to comply. PHMSA determined that the specified timelines are reasonable and practicable given that many operators already implement leak detection systems on their entire network across both HCA and non-HCA miles, and because many operators are constructing and designing new lines with leak detection system capabilities. Further, PHMSA assumes that the cost of extending existing capabilities to non-HCA miles is minimal for systems already equipped with SCADA sensors (see the RIA for details). Certain commenters questioned the methods of leak detection that PHMSA would require to comply with this provision. PHMSA notes that negative pressure wave monitoring, real-time transient modelling, or other external systems are not necessarily required to VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 comply with the rule. The costs of using or installing these leak detection system components were not explicitly analyzed in the RIA; however, operators may voluntarily choose to use these components, as well as any others, to comply with the leak detection requirements of the rule. PHMSA received several comments regarding leak detection system performance criteria, valve spacing requirements, and automatic shutdown capability, which were topics listed in the ANPRM. Due to the complexity of these topics and the need for further study and public comment, PHMSA is pursuing these topics in a separate rulemaking.46 G. Increased Use of ILI Tools in HCAs 1. PHMSA’s Proposal PHMSA proposed to require that all hazardous liquid pipelines in HCAs and areas that could affect an HCA be made capable of accommodating ILI tools within 20 years, unless the basic construction of a pipeline will not accommodate the passage of such a device. The current requirements for the passage of ILI devices in hazardous liquid pipelines are prescribed in § 195.120, which require that new and replaced pipelines be designed to accommodate in-line inspection tools. Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the requirements for the passage of ILI tools to be extended to existing hazardous liquid pipeline facilities, provided the basic construction of those facilities can be modified to permit the use of smart pigs. 2. Summary of Public Comment Trade organizations expressed concern that the NPRM would inhibit operators from exercising their expert judgement in selecting an assessment method and would be overly burdensome. API–AOPL and other industry representatives requested that PHMSA not adopt this proposal because it would require pipelines to incur extensive costs due to age, design, and location of the pipelines, without demonstrating commensurate benefits. They also requested that PHMSA remove the requirement to petition for an exemption under § 190.9 and instead continue to allow operators to exercise their expertise and engineering judgment in using the most effective and efficient methods of evaluating the integrity of their facilities with prior notification to OPS. 46 ‘‘Pipeline Safety: Amendments to Parts 192 and 195 to Require Valve Installation and Minimum Rupture Detection Standards,’’ RIN: 2137–AF06. PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 52285 The IPAA and the American Gas Association (AGA) requested that PHMSA review current studies or conduct an original study to determine if ILI is appropriate to monitor pipeline corrosion given the current state of technology. The AGA also requested that PHMSA provide additional information on what the term ‘‘basic construction’’ meant in the exemption from the ILI-capable requirement. Conversely, citizen groups and individuals recommended that operators use ILI more broadly. An organization representing public safety and other commenters expressed concern with the length of the 20-year implementation period and the multiple exemptions such as where the pipe is constructed in such a way that an ILI device cannot be accommodated. Some of these commenters recommended instead that: (1) PHMSA significantly reduce the timing of accommodating ILI devices, perhaps to 5 years; (2) PHMSA require all new pipelines constructed in HCAs to accommodate ILI devices immediately; (3) PHMSA reexamine and tighten proposed exemptions; and (4) PHMSA establish standards for ILI tools, including the detection of stress corrosion cracking. Congresswoman Capps suggested that PHMSA could establish a shorter time frame of 5 years with an extension possible upon request with sufficient evidence for need and a provided plan of action to meet the standard. The PST recommended that operators integrate close interval survey results into ILI device findings. Other groups commented on the tools used for inspection, the compliance periods, and accountability. The Environmental Defense Center requested that PHMSA require other inspection tools and methods, such as hydrostatic pressure testing, where operators detect certain types of anomalies and when these technologies can provide additional information regarding the condition and vulnerabilities of a pipeline system. The Alliance for Great Lakes et al. recommended that PHMSA develop a framework that assigns different compliance periods for pipelines based on factors such as age, leak history, corrosion, environmental circumstances that could affect the pipeline, and other aspects such as those typically reviewed in IM studies. Finally, California Assembly Member Das Williams requested that operators be required to submit ILI data to PHMSA for review and verification. The NTSB recommended that PHMSA require owners/operators to develop comprehensive implementation plans with transparent progress reporting of E:\FR\FM\01OCR3.SGM 01OCR3 52286 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 intermediate milestones to best ensure operators modify existing pipelines to accommodate the passage of ILI devices within the 20-year time limit. The NTSB also recommended that operators modify all newly identified HCA segments to accommodate an internal inspection tool according to an accelerated schedule, but not more than 5 years after an operator identifies the HCA. During the February 1, 2016, meeting, the LPAC recommended that PHMSA adopt the proposed 20-year implementation period as feasible and cost-effective. In a separate vote, the LPAC reached a tie on a 10-year implementation period, which resulted in a failed motion. The LPAC also recommended that § 195.452(n) be modified to allow an operator to file a petition that ILI tools cannot be accommodated when the operator determines it would abandon or shut down a pipeline as a result of the cost to comply. 3. PHMSA Response PHMSA carefully considered input from commenters and the LPAC in finalizing this rule, which requires that all HCA pipelines whose basic construction would accommodate ILI tools be modified to permit the use of ILI tools within 20 years. Examples of ‘‘basic construction’’ that an operator may be able to show would not accommodate ILI tools include short length, small diameter, diameter changes, low operating pressure, lowvolume flow, location, sharp bends, and terrain. PHMSA shares the interest of commenters who requested expeditious upgrades to the pipeline network to accommodate ILI tools. PHMSA maintains that ILI tools are generally more effective than other methods at detecting integrity issues. ILI tools take advantage of state-of-the-art technological developments and allow operators to identify anomalies and prioritize anomalies without interrupting services. ILI tools also provide a higher level of detail than is possible using other testing tools such as hydrotesting, which allow operators to determine whether a required safety margin is met (i.e., pass/fail) but do not provide information about the existence of anomalies that could deteriorate over time between tests. PHMSA notes that the existing regulation already requires new pipelines to be capable of accommodating ILI tools, as certain commenters requested. Data from operators’ pipeline annual reports suggest that the vast majority of pipeline miles are currently assessed using ILI tools. The mileage not assessed using VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 these tools is likely to consist of pipeline segments, such as small diameter pipes, where ILI is impracticable using the current technologies. Providing sufficient time for ILI tool accommodation projects allows the industry to prioritize these projects based on age or other factors, including the risk factors identified by the Alliance for the Great Lakes in their comments; it also reduces the mileage of pipeline potentially needing to be replaced before they have reached their operational life. PHMSA determined that a 20-year timeline strikes the appropriate balance between the need to make upgrades as soon as possible to enable more effective integrity assessment technologies, with the costs and operational practicalities of making those changes. Given that a preponderance of HCA pipelines can already accommodate ILI tools, exceptions available for specific pipeline designs, operational benefits of ILI over other assessment methods, the continued aging of unpiggable lines, and the 20-year compliance deadline that will further reduce remaining mileage of old pre-ILI pipeline, PHMSA determined that the final rule requirement to make existing HCA pipelines able to accommodate ILI tools is unlikely to impact any amount of the hazardous liquid pipeline infrastructure.47 Accordingly, PHMSA does not estimate any cost for this requirement. PHMSA will consider modifying its annual report form to have hazardous liquid pipeline operators report data on what percentages of their lines are piggable. In response to commenters who sought more immediate implementation, PHMSA notes that inability to use ILI on a pipeline segment does not mean that an operator has not assessed the pipeline; the regulation requires that these pipelines be assessed using alternative approaches, with hydrotesting being the most common alternative. Data reviewed by PHMSA indicates that less than 1 percent of HCA pipeline mileage is assessed using direct assessment methods. Comments about seismicity considerations are addressed in the next section. In response to commenters who requested a specific deadline for making lines in newly identified HCAs capable 47 In the RIA, PHMSA estimates that over 98 percent of pipelines for which ILI is applicable likely are already able to accommodate ILI tools. Given the factors listed here, PHMSA assumes that essentially all HCA lines for which ILII is practicable are currently, or will be within the next 20 years, piggable. Further details are in the RIA for this rulemaking. PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 of accommodating ILI tools, PHMSA notes that operators will have until the end of the 20-year implementation period to make lines piggable. Operators who newly identify HCAs in years 16– 20 of the implementation period and after the 20-year implementation period will have 5 years from the date of the HCA identification to make lines in those areas piggable. H. Clarifying Other Requirements 1. PHMSA’s Proposal PHMSA also proposed several other clarifying changes to the regulations that were intended to improve compliance. First, PHMSA proposed to revise paragraph (b)(1) of § 195.452 to better harmonize the current regulations. The existing § 195.452(b)(2) requires that segments of new pipelines that could affect HCAs be identified before the pipeline begins operations and § 195.452(d)(1) requires that baseline assessments for covered segments of new pipelines be completed by the date the pipeline begins operation. However, § 195.452(b)(1) does not require an operator to draft its IM program for a new pipeline until 1 year after the pipeline begins operation. Improved consistency would be beneficial, as the identification of could affect segments and the performance of baseline assessments are elements of the written IM program. PHMSA proposed to amend the table in (b)(1) to resolve this inconsistency by eliminating the 1-year compliance deadline for Category 3 pipelines. An operator of a new pipeline would be required to develop its written IM program before the pipeline begins operation. PHMSA proposed to add additional specificity to § 195.452(g) by establishing several pipeline attributes that must be included in IM information analyses and to explicitly require that operators integrate analyzed information to help ensure they are properly evaluating interacting threats. PHMSA also proposed that operators explicitly consider any spatial relationships among anomalous information. PHMSA also proposed that operators verify their segment identification annually by determining whether factors considered in their analysis have changed. The change that PHMSA proposed would not require that operators automatically re-perform their segment analyses. Rather, it would require operators to identify the factors considered in their original analyses, determine whether those factors have changed, and consider whether any such change would be likely to affect the results of the original segment E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 identification. If so, the operator would be required to perform a new segment analysis to validate or change the endpoints of the segments affected by the change. PHMSA also proposed to add an explicit reference clarifying that the IM requirements apply to portions of pipeline facilities other than line pipe. Unlike integrity assessments for line pipe, § 195.452 does not include explicit deadlines for completing the analyses of other facilities within the definition of ‘‘pipeline’’ or for implementing actions in response to those analyses. While most operators correctly treat any component that product moves through in areas that could affect HCAs as subject to IM, PHMSA has reason to believe that some operators have not completed analyses of their non-pipe facilities such as pump stations and breakout tanks and have not implemented appropriate protective and mitigative measures. Section 29 of the 2011 Pipeline Safety Act states that ‘‘[i]n identifying and evaluating all potential threats to each pipeline segment pursuant to parts 192 and 195 of title 49, Code of Federal Regulations, an operator of a pipeline facility shall consider the seismicity of the area.’’ While seismicity is already mentioned at several points in the IM program guidance provided in Appendix C of part 195, PHMSA proposed to further comply with Congress’s directive by including an explicit reference to seismicity in the list of risk factors that must be considered in establishing assessment schedules (§ 195.452(e)), performing information analyses (§ 195.452(g)), and implementing preventive and mitigative measures (§ 195.452(i)) under the IM requirements. 2. Summary of Public Comment Trade organizations commented primarily on the implementation period for PHMSA’s clarifications on data integration and the attributes and information required. Other trade associations joined API–AOPL in requesting a 5-year implementation schedule for integrating these specific attributes, including populating data into information systems and validating the quality of the data process. The AGA recommended that PHMSA focus on the analysis of information and attributes rather than their integration. Trade organizations also requested flexibility in developing the attributes and information required in data analysis. The AGA requested that operators independently develop the list of information and attributes to be included in data analysis. They also VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 commented that there is no current regulatory requirement for an operator of hazardous liquid or natural gas pipelines to maintain or utilize a GIS. Finally, trade organizations expressed concern with changes to the baseline assessment of newly constructed pipelines. API–AOPL requested that PHMSA clarify that hydrostatic testing is an acceptable method of meeting this requirement for new construction. During the February 1, 2016, meeting, the LPAC recommended that PHMSA modify the NPRM to require data integration to begin in year one, with all attributes completed within 3 years. 3. PHMSA Response PHMSA appreciates the information provided by the commenters. As discussed at the LPAC meeting, integrating data is a key element and concept of continuous improvement and IM. The requirement that operators perform data integration has long been a part of IM program requirements. The attributes that PHMSA proposed in the NPRM were factors operators should have already been considering when assessing risk to their pipelines— PHMSA is merely codifying them to better ensure all operators are utilizing them. PHMSA understands that the need for some operators to enhance their data systems to fit these specific attributes will take some time and effort. Because of this, PHMSA agrees with the LPAC that operators should be given a maximum of 3 years to fully comply and integrate all the proposed attributes into their data integration systems, with implementation beginning once the rule is published. However, this implementation period does not mean operators should lapse in what they are currently required to perform under § 195.452(g). PHMSA expects operators to add the attributes issued in this final rule to their current data integration systems and efforts. While PHMSA is sympathetic to allowing operators more flexibility with the attributes that should be considered for data integration, experience has shown that PHMSA needs to prescribe a common baseline set of attributes for operators to assess. PHMSA agrees with commenters who believe hydrostatic testing is an acceptable baseline assessment method for newly constructed pipelines and is incorporating that option into this final rule. As operators are required to conduct hydrostatic tests on all newly constructed pipelines prior to operation, and PHMSA allows operators to use hydrostatic testing for subsequent assessments, PHMSA has determined this could eliminate additional PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 52287 duplicative baseline assessments and reduce operator burden. V. PIPES Act of 2016 On June 22, 2016, the President signed the PIPES Act of 2016, Public Law 114–183, containing Sections 14 and 25, ‘‘Safety Data Sheets’’ and ‘‘Requirements for Certain Hazardous Liquid Pipeline Facilities,’’ respectively. The language in both Section 14 and Section 25 is self-executing, with Section 25 specifically amending the Pipeline Safety Act at 49 U.S.C. 60109 by adding new paragraphs (g) through (g)(4). To allow the timely implementation of these sections of the PIPES Act of 2016 and to help ensure regulatory certainty, PHMSA has determined that good cause exists for finding that notice and comment on these provisions is impracticable and contrary to the public interest and is subsequently incorporating them into this final rule. Section 14 of the PIPES Act of 2016 requires owners and operators of hazardous liquid pipeline facilities, following accidents involving pipeline facilities that result in hazardous liquid spills and within 6 hours of a telephonic or electronic notice of the accident to the National Response Center, to provide safety data sheets on any spilled hazardous liquid to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders. PHMSA has incorporated this requirement in a new § 195.65 under the reporting requirements of Subpart B. Section 25 of the PIPES Act of 2016 applies to operators of any underwater hazardous liquid pipeline facility located in an HCA that is not an offshore pipeline facility and any portion of which is located at depths greater than 150 feet under the surface of the water. Operators of these facilities, notwithstanding any pipeline integrity management program or integrity assessment schedule otherwise required by the Secretary, must ensure that pipeline integrity assessments using internal inspection technology appropriate for the pipeline’s integrity threats are completed not less often than once every 12 months; and using pipeline route surveys, depth of cover surveys, pressure tests, ECDA, or other technology that the operator demonstrates can further the understanding of the condition of the pipeline facility, ensure that pipeline integrity assessments are completed on a schedule based on the risk that the pipeline facility poses to the HCA in which the pipeline facility is located. PHMSA has incorporated these E:\FR\FM\01OCR3.SGM 01OCR3 52288 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations previously approved by the Director of the Federal Register and is not changed by this rule. requirements in a new § 195.454 as an addition to the pipeline integrity management requirements under subpart F. VI. Section-by-Section Analysis § 195.1 Which pipelines are covered by this part? Section 195.1(a) lists the pipelines that are subject to the requirements in 49 CFR part 195, including gathering lines that cross waterways used for commercial navigation as well as certain onshore gathering lines (i.e., those that are in a non-rural area, that meet the definition of a regulated onshore gathering line, or that are in an inlet of the Gulf of Mexico). PHMSA has determined it needs additional information about unregulated gathering lines to fulfill its statutory obligations, and it has determined it needs additional information about gravity lines to determine whether any safety regulations need to be extended to these lines as well. Accordingly, this final rule extends the reporting requirements in subpart B of part 195 to all gravity and gathering lines (whether regulated, unregulated, onshore, or offshore). jbell on DSK3GLQ082PROD with RULES3 § 195.2 Definitions Section 195.2 provides definitions for various terms used throughout part 195. On August 10, 2007, PHMSA published a policy statement and request for comment on the transportation of ethanol, ethanol blends, and other biofuels by pipeline (72 FR 45002). PHMSA noted in the policy statement that the demand for biofuels was projected to increase in the future because of several Federal energy policy initiatives, and that the predominant modes for transporting such commodities (i.e., truck, rail, or barge) would expand over time to include greater use of pipelines. PHMSA also stated that ethanol and other biofuels are substances that ‘‘may pose an unreasonable risk to life or property’’ within the meaning of 49 U.S.C. 60101(a)(4)(B) and accordingly these materials constitute ‘‘hazardous liquids’’ for purposes of the pipeline safety laws and regulations. PHMSA is modifying the definition of ‘‘hazardous liquid’’ in § 195.2 to conform with 49 U.S.C. 60101(a)(4)(B) and clarify that the transportation of biofuel by pipeline is subject to the requirements of 49 CFR part 195. Section 195.3 What documents are incorporated by reference partly or wholly in this part? The incorporation by reference of NACE SP0102 and API RP 1130 was VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 Section 195.13 What requirements apply to pipelines transporting hazardous liquids by gravity? Section 195.13 is added to subject gravity lines to the same annual, accident, and safety-related condition reporting requirements in subpart B of part 195 as other hazardous liquid pipelines. Section 195.15 What reporting requirements apply to reportingregulated-only gathering lines? Section 195.15 is added to subject otherwise unregulated rural gathering lines and certain offshore lines in State waters to the annual, accident and safety-related condition reporting requirements in subpart B of part 195 as other hazardous liquid pipelines. Section 195.65 Safety Data Sheets Section 195.65 contains the requirements for providing safety data sheets on spilled hazardous liquids following accidents. In accordance with Section 14 of the PIPES Act of 2016, PHMSA is requiring owners and operators of hazardous liquid pipeline facilities, following accidents that result in hazardous liquid spills, to provide safety data sheets on those spilled hazardous liquids to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. This is a self-executing provision from the PIPES Act of 2016 that PHMSA is incorporating into subpart B of the hazardous liquid pipeline safety regulations. Section 195.120 Passage of Internal Inspection Devices Section 195.120 contains the requirements for accommodating the passage of internal inspection devices in the design and construction of new or replaced pipelines. PHMSA has decided that, in the absence of an emergency, or where the basic construction makes that accommodation impracticable, a pipeline should be designed and constructed to permit the use of ILIs. Accordingly, this final rule repeals the provisions in the regulation that allow operators to petition the Administrator for a finding that the ILI compatibility requirement should not apply as a result of construction-related time constraints and problems. The other provisions in § 195.120 are re-organized without PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 altering the existing substantive requirements. Section 195.134 Leak Detection Section 195.134 contains the design requirements for computational pipeline monitoring leak detection systems. The final rule restructures the existing requirements into paragraphs (a) and (c) and adds a new provision in paragraphs (b) and (d) to ensure that all newly constructed, covered pipelines are designed to include leak detection systems based upon standards in section 4.2 of API 1130 or other applicable design criteria in the standard. Section 195.401 General Requirements Section 195.401 prescribes general requirements for the operation and maintenance of hazardous liquid pipelines. PHMSA is modifying the pipeline repair requirements in § 195.401(b). PHMSA is retaining, without change, the requirements in paragraphs (b)(1) for non-IM repairs and (b)(2) for IM repairs. A new paragraph (b)(3) is added, however, to clearly require operators to consider the risk to people, property, and the environment in prioritizing the remediation of any condition that could adversely affect the safe operation of a pipeline system, no matter whether those conditions are in HCAs or non-HCAs. Section 195.414 Inspections of Pipelines in Areas Affected by Extreme Weather and Natural Disasters Extreme weather and natural disasters can affect the safe operation of a pipeline. Accordingly, this final rule establishes a new § 195.414 that requires operators to perform inspections after these events and to take appropriate remedial actions. Section 195.416 Pipeline Assessments Periodic assessments, particularly with ILI tools, provide critical information about the condition of a pipeline, but are only currently required under IM requirements in §§ 195.450 through 195.452. PHMSA has determined that operators should be required to have the information needed to promptly detect and remediate conditions that could affect the safe operation of pipelines in all areas. Accordingly, the final rule establishes a new § 195.416 that requires operators to perform an assessment, at least once every 10 years, of onshore pipelines that can accommodate inline inspection tools and that are not already subject to the IM requirements. This assessment must be performed for the range of relevant threats to the pipeline segment using an appropriate ILI tool(s) and E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations account for uncertainties in reported results. Operators must use a method capable of assessing seam integrity and corrosion and deformation anomalies when assessing LF–ERW pipe, lapwelded pipe, or pipe with a seam factor of less than 1.0. In lieu of performing an ILI assessment on their lines, operators can perform the assessment by using a pressure test, external corrosion direct assessment, or other technology (subject to prior notification, method being able to assess the threat, and ‘‘no objection’’ by PHMSA) that can be demonstrated as providing an equivalent understanding of the pipe’s condition. The regulation also requires that the results of these assessments be reviewed by a person qualified to determine if any conditions exist that could affect the safe operation of a pipeline; that such determinations be made promptly, but no later than 180 days after the assessment; that any unsafe conditions be remediated in accordance with the repair requirements in § 195.401(b)(1); and that all relevant information about the pipeline be considering in complying with the requirements of § 195.416. Consistent with the requirements in the revised § 195.452(h)(2) regarding the discovery of condition, in cases where the information necessary to make determination about pipeline threats cannot be obtained within 180 days following the date of inspection, pipeline operators must notify PHMSA and provide an expected date when adequate information will become available. jbell on DSK3GLQ082PROD with RULES3 Section 195.444 Leak Detection Section 195.444 contains the operation and maintenance requirements for Computational Pipeline Monitoring leak detection systems. PHMSA is amending the PSR so that all covered hazardous liquid pipelines have a leak detection system. Therefore, the final rule reorganizes the existing requirements of the regulation into paragraphs (a) and (c), and adds a new general provision in paragraph (b) that requires operators to have leak detection systems on all covered pipelines and to consider certain factors in determining what kind of system is necessary to protect the public, property, and the environment. Section 195.452 Pipeline Integrity Management in High Consequence Areas Section 195.452 contains the IM requirements for hazardous liquid pipelines that could affect a HCA in the event of a leak or failure. The final rule clarifies the applicability of the VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 deadlines in paragraph (b) for the development of a written program for new pipelines and low-stress pipelines in rural areas. The rule also makes the following amendments to paragraphs (c) through (o): • Paragraph (c)(1)(i)(A) is amended to ensure that operators consider uncertainty in tool tolerance in reviewing the results of ILI assessments. The paragraph is also amended to be more consistent with paragraphs at § 195.416 by stating that pipeline segments with identified or probable risks or threats related to cracks (such as at pipe body and weld seams) based on the risk factors specified in paragraph (e), an operator must use an ILI tool or tools capable of detecting crack anomalies. • Paragraph (d) is amended to eliminate obsolete deadlines for performing baseline assessments and to clarify the requirements for newly identified HCAs. The deletion of these previous compliance dates does not change or delete any associated recordkeeping requirements or implement any new recordkeeping requirements. Operators should retain the records they have used to show compliance regarding the baseline assessment deadlines. • Paragraph (e)(1)(vii) is amended to include local environmental factors, including seismicity, that might affect pipeline integrity. • Paragraph (g) is amended to prescribe certain data points and criteria that operators must consider in performing the information analysis required to evaluate periodically the integrity of covered pipeline segments. • Paragraph (h)(2) is amended to require that in those situations where an operator must obtain adequate information within 180 days after an integrity assessment to determine whether an anomalous condition could present a potential integrity threat of the pipeline but the operator believes it is impracticable to obtain sufficient information within that period, the operator must notify PHMSA and provide an expected date when adequate information will become available. • Paragraph (j) is amended to establish a new provision for verifying the risk factors used in identifying covered segments on at least an annual basis, not to exceed 15 months. • A new paragraph (n) is added to require that all pipelines in areas that could affect an HCA be made capable of accommodating ILI tools within 20 years, unless, subject to a petition and PHMSA approval, the basic construction of a pipeline will not PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 52289 permit that accommodation, the existence of an emergency renders such an accommodation impracticable, or the operator determines it would abandon or shut down a pipeline as a result of the cost to comply with the requirement of this section. Paragraph (n) requires that pipelines in newly identified HCAs after the 20-year period be made capable of accommodating ILIs within 5 years of the date of identification or before the performance of the baseline assessment, whichever is sooner. • Paragraph (o) is added to allow operators additional time to integrate the additional information and attributes that PHMSA has added to the information analysis required under paragraph (g)(1). • Finally, an explicit reference to seismicity is added to factors that must be considered in establishing assessment schedules under paragraph (e), for performing information analyses under paragraph (g), and for implementing preventive and mitigative measures under paragraph (i). Section 195.454 Integrity Assessments for Certain Underwater Hazardous Liquid Pipeline Facilities Located in HCAs Section 195.454 contains additional assessment requirements for operators of any underwater hazardous liquid pipeline facility located in an HCA that is not an offshore pipeline facility and any portion of which is located at depths greater than 150 feet under the surface of the water. In accordance with section 25 of the PIPES Act of 2016, PHMSA is requiring these operators to ensure that they complete pipeline integrity assessments not less often than once every 12 months using internal inspection technology appropriate for the integrity threats to the pipeline and complete pipeline integrity assessments using pipeline route surveys, depth of cover surveys, pressure tests, external corrosion direct assessment, or other technology that the operator demonstrates can further the understanding of the condition of the pipeline facility, on a schedule based on the risk that the pipeline facility poses to the HCA in which the pipeline facility is located. This is a selfexecuting provision from the PIPES Act of 2016 that PHMSA is incorporating into subpart F of the hazardous liquid pipeline safety regulations. VII. Regulatory Notices A. Statutory/Legal Authority for This Rulemaking This final rule is published under the authority of the Federal Pipeline Safety E:\FR\FM\01OCR3.SGM 01OCR3 52290 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes the Secretary of Transportation to issue regulations governing design, installation, inspection, emergency plans and procedures, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities, as delegated to the PHMSA Administrator under 49 CFR 1.97. PHMSA is revising the ‘‘Authority’’ entry for part 195 to include a citation to a provision of the Mineral Leasing Act (MLA), specifically, 30 U.S.C. 185(w)(3). Section 185(w)(3) provides that ‘‘[p]eriodically, but at least once a year, the Secretary of the Department of Transportation shall cause the examination of all pipelines and associated facilities on Federal lands and shall cause the prompt reporting of any potential leaks or safety problems.’’ The Secretary has delegated this responsibility to PHMSA (49 CFR 1.97). PHMSA has traditionally complied with § 185(w)(3) through the issuance of its pipeline safety regulations, which require annual examinations and prompt reporting for all or most of the pipelines they cover. PHMSA is making this change to be consistent with and make clear its long-standing position that the agency complies with the MLA through the issuance of pipeline safety regulations. B. Executive Order 12866 and DOT Regulatory Policies and Procedures This final rule is a significant regulatory action under Section 3(f) of Executive Order 12866 (58 FR 51735), and therefore was reviewed by the Office of Management and Budget. This final rule is significant under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034) because of substantial congressional, State, industry, and public interest in pipeline safety. In the regulatory analysis, PHMSA discusses the alternatives to the amended requirements and, where possible, provides estimates of the benefits and costs for specific regulatory requirements by individual requirement areas. The regulatory analysis provides PHMSA’s best estimate of the impact of the final rule requirements. As shown in the table below, PHMSA estimated the total annual costs of the rule at $19.5 million using a 3 percent discount rate and $21.4 million using a 7 percent discount rate. Due to data limitations, PHMSA evaluated the benefits of the final rule qualitatively. Overall, the rule will provide direct benefits through avoiding damages from hazardous pipeline incidents that may be prevented through earlier detection of threats to pipeline integrity from corrosion or following extreme weather events, and through enhancing the ability of PHMSA and pipeline operators to evaluate risks. As context, operator-reported data for hazardous liquid incidents that occurred between 2010 and 2017 show reported average annual damages of $91.6 million for pipelines outside HCAs and $265.8 million for pipelines inside HCAs, or about $815 and $3,222 per mile of hazardous liquid pipeline, respectively. These damages are only a fraction of the total social costs of hazardous liquid releases but indicate the potential magnitude of benefits derived from preventing pipeline failures. ANNUALIZED COSTS AND BENEFITS BY REQUIREMENT AREA (2017$) 48 Annual costs 1 jbell on DSK3GLQ082PROD with RULES3 Final rule requirement area Benefits 3% Discount rate 7% Discount rate $5,000 ................... $75,000 ................. Minimal .................. $5,000 ................... $76,000 ................. Minimal .................. 1. Reporting requirements for gravity lines ........... 2. Reporting requirements for gathering lines ....... 3. Inspections of pipelines in areas affected by extreme weather events 4. 4. Assessments of onshore pipelines that are not already covered under the IM program using ILI every 10 years 5 6. 5. IM repair criteria 8 .............................................. 6. LDSs on pipelines located outside HCAs 6 ....... $6,467,000 ............ $6,467,000 ............ $0 .......................... $8,652,000 ............ $0 .......................... $10,508,000 .......... 7. Increased use of ILI tools 10 .............................. 8. Clarify certain IM plan requirements. ................ Minimal .................. $4,269,000 ............ Minimal .................. $4,343,000 ............ Total ................................................................ $19,468,000 .......... $21,399,000 .......... Better risk understanding and management.2 Better risk understanding and management.3 Additional clarity and certainty for pipeline operators. Avoided incidents and damages through detection of safety conditions.7 $0. Reduced damages through earlier detection and response.9 Improved detection of pipeline flaws.10 Reduced damages through prevention and earlier detection and response.11 Reduced damages from avoiding and/or mitigating hazardous liquid releases. 1 Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in individual sections of the document. One-time costs are annualized over a 10-year period using discount rates of 3 percent and 7 percent. 2 Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of 101 gallons per year to generate benefits that equal the costs. 3 The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of 1,493 gallons per year to generate benefits that equal the costs. 4 To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not reflected in this analysis. 5 PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios: (1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two scenarios are $0 and $12.9 million, respectively. 6 Excludes gathering lines. 7 Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to prevent 12 incidents for benefits to equate costs. 8 PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or benefits. 48 Numbers in this table may not sum due to rounding. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 PO 00000 Frm 00032 Fmt 4701 Sfmt 4700 E:\FR\FM\01OCR3.SGM 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations 52291 9 As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of approximately $382,179, not including additional damages and costs that are excluded or underreported in the incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents. 10 Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be minimal due to baseline prevalence of ILI-capable pipelines in all areas. 11 The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids cannot be quantified but could vary in frequency and size depending on the types of failures that are averted. Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected to enhance an operator’s ability to identify and address risk. The societal costs associated with incidents involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates for this requirement are equivalent to the average damages from less than three such incidents. This is relative to an annual average of 161 incidents in HCAs between 2010 and 2017. Overall, factors such as increased safety, public confidence that all pipelines are regulated, quicker discovery of leaks and mitigation of environmental damages, and better risk management are expected to yield benefits that exceed or otherwise justify the costs. A copy of the final RIA has been placed in the docket. Pursuant to the Congressional Review Act (5 U.S.C. 801 et seq., the Office of Information and Regulatory Affairs designated this rule as not a ‘‘major rule,’’ as defined by 5 U.S.C. 804(2). C. Executive Order 13771: Reducing Regulation and Controlling Regulatory Costs The final rule is an Executive Order 13771 regulatory action. Details on the estimated costs of this final rule can be found in the rule’s economic analysis. D. Executive Order 13132: Federalism This final rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (‘‘Federalism’’). This final rule does not adopt any regulation that has substantial direct effects on the states, the relationship between the national government and the states, or the distribution of power and responsibilities among the various levels of government. It does not adopt any regulation that imposes substantial direct compliance costs on state and local governments. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. jbell on DSK3GLQ082PROD with RULES3 E. Regulatory Flexibility Act The Regulatory Flexibility Act of 1980 (Pub. L. 96–354) (RFA) establishes ‘‘as a principle of regulatory issuance that agencies shall endeavor, consistent with the objectives of the rule and of applicable statutes, to fit regulatory and informational requirements to the scale of the businesses, organizations, and governmental jurisdictions subject to regulation. To achieve this principle, agencies are required to solicit and consider flexible regulatory proposals and to explain the rationale for their actions to assure that such proposals are given serious consideration.’’ VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 The RFA covers a wide range of small entities, including small businesses, not-for-profit organizations, and small governmental jurisdictions. Agencies must perform a review to determine whether a rule will have a significant economic impact on a substantial number of small entities. If the agency determines that it will, the agency must prepare a regulatory flexibility analysis as described in the RFA. However, if an agency determines that a rule is not expected to have a significant economic impact on a substantial number of small entities, section 605(b) of the RFA provides that the head of the agency may so certify and a regulatory flexibility analysis is not required. The certification must include a statement providing the factual basis for this determination, and the reasoning should be clear. PHMSA performed a screening analysis of the economic impact on small entities. The screening analysis is available in the docket for the rulemaking. PHMSA estimates that compliance costs may exceed 1 percent of sales for 23 to 31 of the estimated small businesses and may exceed 3 percent of sales for 9 to 10 small businesses. The higher number of affected small businesses assumes that the operator incurs costs for all applicable requirements. Given the small number and percentage of small businesses affected, the small sales test ratios, and the noted flexibility, PHMSA determined that the final rule will not have a significant impact on a substantial number of small entities.49 Therefore, I certify that this action does not have a significant economic impact on a substantial number of small entities. F. National Environmental Policy Act PHMSA analyzed this final rule in accordance with section 102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), the Council on Environmental Quality regulations (40 CFR parts 1500 through 1508), and DOT Order 5610.1C, and has determined that 49 Based on SBA (2013), including criteria developed by other agencies. PO 00000 Frm 00033 Fmt 4701 Sfmt 4700 this action will not significantly affect the quality of the human environment. An environmental assessment of this rulemaking is available in the docket. G. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This final rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13175 (‘‘Consultation and Coordination with Indian Tribal Governments’’). Because this final rule does not have Tribal implications and does not impose substantial direct compliance costs on Indian Tribal governments, the funding and consultation requirements of Executive Order 13175 do not apply. H. Paperwork Reduction Act Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide interested members of the public and affected agencies with an opportunity to comment on information collection and recordkeeping requests. PHMSA estimates the proposals in this rulemaking will impact the following information collections: ‘‘Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting’’ identified under Office of Management and Budget (OMB) Control Number 2137–0047; ‘‘Reporting Safety-Related Conditions on Gas, Hazardous Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities’’ identified under OMB Control Number 2137–0578; ‘‘Integrity Management in High Consequence Areas for Operators of Hazardous Liquid Pipelines’’ identified under OMB Control Number 2137–0605; ‘‘Pipeline Safety: Reporting Requirements for Hazardous Liquid Pipeline Operators: Hazardous Liquid Annual Report’’ identified under OMB Control Number 2137–0614; ‘‘National Registry of Pipeline and LNG Operators’’ identified under OMB Control Number 2137–0627; and ‘‘Operator Notifications—Alternate Pressure Testing Method’’ identified under OMB Control Number 2137–0630. PHMSA will submit an information collection revision request to OMB for E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 52292 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations approval based on the requirements in this rule. These information collections are contained in the Federal Pipeline Safety Regulations, 49 CFR parts 190– 199. The following information is provided for each information collection: (1) Title of the information collection; (2) OMB control number; (3) Current expiration date; (4) Type of request; (5) Abstract of the information collection activity; (6) Description of affected public; (7) Estimate of total annual reporting and recordkeeping burden; and (8) Frequency of collection. The information collection burden for the following information collections are estimated to be revised as follows: 1. Title: Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting. OMB Control Number: 2137–0047. Current Expiration Date: 08/31/2020. Abstract: This information collection covers the collection of information from owners and operators of hazardous liquid pipelines. To ensure adequate public protection from exposure to potential hazardous liquid pipeline failures, PHMSA collects information on reportable hazardous liquid pipeline accidents. 49 CFR 195.54 requires hazardous liquid operators to file an accident report, as soon as practicable, but not later than 30 days after discovery of the accident, on DOT Form 7000–1 whenever there is a reportable accident the characteristics of an operator’s pipeline system. The final rule will require operators of both gravity lines and gathering lines to be subject to these accident reporting requirements. Thus, PHMSA expects an additional 28 HL pipeline operators (23 gathering line operators and approximately 5 gravity line operators) to be added to the reporting community. If the frequency of accidents is the same for non-regulated gathering lines and gravity lines as it is for transmission lines, approximately 4 to 6 percent of these newly regulated operators will submit an accident report in any given year. Of the 23 new gathering line operators, PHMSA expects 5 accident reports to be filed per year. Of the 5 new gravity line operators, PHMSA expects 1 accident report to be filed per year. This results in an added burden of 6 new accident reports per year at 10 hours per report for a total added burden of 60 hours for accident reporting. The final rule will also amend the Pipeline Safety Regulations (PSR) in 49 CFR 195.65 to require all owners and operators of hazardous liquid pipeline facilities, following accidents that result in hazardous liquid spills, to provide safety data sheets on those spilled hazardous liquids to the designated VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. PHMSA expects hazardous liquid operators to file approximately 406 accident reports per year. This will result in an added burden of 406 new notifications per year. PHMSA expects that it will take operators 30 minutes to conduct the required task. This will result in an added burden of 406 records at .5 hours per record for a total added burden of 203 hours for safety data sheet notifications recordkeeping. This information collection is being revised to account for the additional burden that will be incurred because of these new provisions. Affected Public: Owners and operators of hazardous liquid pipelines. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 1,644. Total Annual Burden Hours: 52,692. Frequency of Collection: On occasion. 2. Title: Reporting Safety-Related Conditions on Gas, Hazardous Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities. OMB Control Number: 2137–0578. Current Expiration Date: 8/31/2022. Abstract: 49 U.S.C. 60102 requires each operator of a pipeline facility (except master meter operators) to submit to U.S. DOT a written report on any safety-related condition that causes or has caused a significant change or restriction in the operation of a pipeline facility or a condition that is a hazard to life, property or the environment. This rule will require operators of both gravity lines and gathering lines to be subject to safety-related condition reporting. While there is no guarantee that each of the newly covered operators will incur a safety-related condition, it is a possibility. As a result, PHMSA plans to include an additional 28 hazardous liquid pipeline operators (23 gathering line operators and approximately 5 gravity line operators) in this reporting community. PHMSA estimates that it takes each operator 6 hours to complete a safety-related condition report. The addition of the 28 newly covered operators will result in 28 additional responses and an added burden of 168 hours (28 operators * 6 hours). This information collection is being revised to account for the additional burden that will be incurred by newly regulated entities. Operators currently submitting annual reports will not be otherwise impacted by this rule. Affected Public: Owners and operators of hazardous liquid pipelines. PO 00000 Frm 00034 Fmt 4701 Sfmt 4700 Annual Reporting and Recordkeeping Burden: Total Annual Responses: 174. Total Annual Burden Hours: 1,044. Frequency of Collection: On occasion. 3. Title: Hazardous Liquid Pipeline Assessment Requirements. OMB Control Number: 2137–0605. Current Expiration Date: 09/30/2022. Abstract: Owners and operators of hazardous liquid pipelines are required to have continual assessment and evaluation of pipeline integrity through inspection or testing, as well as remedial preventive and mitigative actions. Because of this rulemaking action, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, pipeline operators are required to notify PHMSA in writing and provide an expected date when adequate information will become available. PHMSA estimates that only 1 percent of repair reports (approx. 74) will require these notifications each year. Operators are authorized to send the notification, via email, to PHMSA’s Information Resources Manager. PHMSA estimates that it will take operators 30 minutes to create and send each notification resulting in an overall burden increase of 37 hours annually. Hazardous liquid pipeline operators are also required to notify PHMSA when they are unable to assess their pipeline via an in-line inspection. Operators who choose to use an alternate assessment method must demonstrate that their pipeline is not capable of accommodating an in-line inspection tool and that the use of an alternative assessment method will provide a substantially equivalent understanding of the condition of the pipeline. PHMSA estimates that operators will submit approximately 10 notifications each year regarding these conditions. Further, PHMSA estimates that each notification will take 10 hours, which includes the time to assemble the necessary information to demonstrate that the pipeline is not capable of accommodating an ILI tool and specify that the alternative assessment method will provide a substantially equivalent understanding of the pipeline. This will result in an annual notification burden of 100 hours. The overall annual burden increase for this information collection is 84 responses and 137 hours. PHMSA requests the title of this information collection, previously ‘‘Integrity Management in High Consequence Areas for Operators of Hazardous Liquid Pipelines,’’ be changes to better align with the requested data. E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations Affected Public: Owners and operators of Hazardous Liquid Pipelines. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 287. Total Annual Burden Hours: 325,607. Frequency of Collection: Annually. 4. Title: Pipeline Safety: Reporting Requirements for Hazardous Liquid Pipeline Operators: Hazardous Liquid Annual Report. OMB Control Number: 2137–0614. Current Expiration Date: 01/31/2022. Abstract: Owners and operators of hazardous liquid pipelines are required to provide PHMSA with safety-related documentation relative to the annual operation of their pipeline. The provided information is used to compile a national pipeline inventory, identify safety problems, and target inspections. Due to provisions within this final rule, approximately 5 gravity line operators and 23 gathering line operators will be required to submit annual reports to PHMSA. PHMSA estimates the burden associated with annual reporting activities to be approximately 19 hours per report, composed of 12 hours of a compliance officer’s time and 7 hours of a secretary/ administrative assistant’s time. The newly regulated gravity and gathering line operators will cause an added burden of 28 new annual reports per year at 19 hours per report for a total added burden of 532 hours for annual reporting. This information collection is being revised to account for the additional burden that will be incurred by the newly affected operators. Operators currently submitting annual reports will not be otherwise impacted by this rule. Affected Public: Owners and operators of hazardous liquid pipelines. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 475. Total Annual Burden Hours: 8,989. Frequency of Collection: Annually. 5. Title: National Registry of Pipeline and LNG Operators. OMB Control Number: 2137–0627. Current Expiration Date: 04/301/2022. Abstract: The National Registry of Pipeline and LNG Operators serves as the storehouse for the reporting requirements for an operator regulated under or subject to reporting requirements of 49 CFR parts 191, 192, 193, or 195. The final rule requires operators of both gravity lines and gathering lines to be subject to various reporting requirements. Thus, approximately 5 gravity line operators and 23 gathering line operators will be required to register their pipeline with VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 the National Pipeline Registry and apply for an Operator Identification number (OPID). PHMSA estimates that this activity will take 1 hour per operator to register. Gravity and gathering line operators will also be required to notify PHMSA of certain changes made to their pipeline system when applicable. PHMSA estimates that 5 percent (approximately 1) of these newly regulated operators will make these notifications each year. PHMSA estimates that this activity will take 1 hour per operator. This information collection is being revised to account for the additional burden (29 responses × 1 hour = 29 hours) that will be incurred by the newly regulated operators. Operators currently registered will not be otherwise impacted by this rule. Affected Public: Natural gas, LNG, and hazardous liquid pipeline operators. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 718. Total Annual Burden Hours: 718. 6. Title: Hazardous Liquid Operator Notifications. OMB Control Number: 2137–0630. Current Expiration Date: N/A. Abstract: The Pipeline Safety regulations contained within 49 CFR part 195 require hazardous liquid operators to notify PHMSA in various instances. 49 CFR 195.414 requires hazardous liquid operators who are unable to inspect their pipeline facilities within 72 hours of an extreme weather event to notify the appropriate PHMSA Region Director as soon as practicable. PHMSA expects to receive 100 of these notifications annually. PHMSA believes it will take operators approximately 15 minutes (0.25 hours) to make this notification and send it to the Regional Director electronically. PHMSA expects the annual burden for this requirement to be 25 hours. 49 CFR 195.452 requires operators of pipelines that cannot accommodate an in-line inspection tool to file a petition in compliance with 49 CFR 190.9. PHMSA expects to receive 10 of these notifications annually. PHMSA expects that it will take operators 10 hours to provide records to demonstrate that their pipeline cannot accommodate an inline inspection device for an overall annual burden of 100 hours for this notification requirement. Affected Public: Owners and operators of hazardous liquid pipelines. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 110. Total Annual Burden Hours: 125. PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 52293 Frequency of Collection: Annually. Requests for copies of these information collections should be directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline Safety (PHP–30), Pipeline and Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590– 0001, Telephone (202) 366–4595. Comments are invited on: (a) The need for the proposed collection of information for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) The accuracy of the agency’s estimate of the burden of the revised collection of information, including the validity of the methodology and assumptions used; (c) Ways to enhance the quality, utility, and clarity of the information to be collected; and (d) Ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques. Those desiring to comment on these information collections should send comments directly to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attn: Desk Officer for the Department of Transportation, 725 17th Street NW, Washington, DC 20503. Comments should be submitted on or prior to October 31, 2019. Comments may also be sent via email to the Office of Management and Budget at the following address: oira_submissions@ omb.eop.gov. OMB is required to make a decision concerning the collection of information requirements contained in this final rule between 30 and 60 days after publication of this document in the Federal Register. Therefore, a comment to OMB is best assured of having its full effect if received within 30 days of publication. I. Privacy Act Statement Anyone is able to search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review DOT’s complete Privacy Act Statement in the Federal Register published on April 11, 2000 (65 FR 19477), or at https:// www.regulations.gov. E:\FR\FM\01OCR3.SGM 01OCR3 52294 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations J. Regulation Identifier Number (RIN) A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN contained in the heading of this document may be used to crossreference this action with the Unified Agenda. List of Subjects in 49 CFR Part 195 Incorporation by reference, Integrity management, Pipeline safety. In consideration of the foregoing, PHMSA is amending 49 CFR part 195 as follows: PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE 1. Revise the authority citation for part 195 to read as follows: ■ Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq., and 49 CFR 1.97. 2. Amend § 195.1 by adding paragraph (a)(5) and revising paragraphs (b)(2) and (b)(4) to read as follows: ■ § 195.1 Which pipelines are covered by this part? (a) * * * (5) For purposes of the reporting requirements in subpart B of this part, any gathering line not already covered under paragraphs (a)(1), (2), (3) or (4) of this section. (b) * * * (2) Except for the reporting requirements of subpart B of this part, see § 195.13, transportation of a hazardous liquid through a pipeline by gravity. * * * * * (4) Except for the reporting requirements of subpart B of this part, see § 195.15, transportation of petroleum through an onshore rural gathering line that does not meet the definition of a ‘‘regulated rural gathering line’’ as provided in § 195.11. This exception does not apply to gathering lines in the inlets of the Gulf of Mexico subject to § 195.413. * * * * * ■ 3. Amend § 195.2 by revising the definition for ‘‘Hazardous liquid’’ to read as follows: jbell on DSK3GLQ082PROD with RULES3 § 195.2 Definitions. * * * * * Hazardous liquid means petroleum, petroleum products, anhydrous ammonia, and ethanol or other nonpetroleum fuel, including biofuel, which is flammable, toxic, or would be VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 harmful to the environment if released in significant quantities. * * * * * § 195.3 [Amended] 4. In § 195.3, amend paragraph (g)(3) by removing ‘‘§ 195.591’’ and adding ‘‘§§ 195.120 and 195.591’’ in its place. ■ 5. Add § 195.13 to subpart A to read as follows: ■ § 195.13 What requirements apply to pipelines transporting hazardous liquids by gravity? (a) Scope. Pipelines transporting hazardous liquids by gravity must comply with the reporting requirements of subpart B of this part. (b) Implementation period—(1) Annual reporting. Comply with the annual reporting requirements in subpart B of this part by March 31, 2021. (2) Accident and safety-related reporting. Comply with the accident and safety-related condition reporting requirements in subpart B of this part by January 1, 2021. (c) Exceptions. (1) This section does not apply to the transportation of a hazardous liquid in a gravity line that meets the definition of a low-stress pipeline, travels no farther than 1 mile from a facility boundary, and does not cross any waterways used for commercial navigation. (2) The reporting requirements in §§ 195.52, 195.61, and 195.65 do not apply to the transportation of a hazardous liquid in a gravity line. (3) The drug and alcohol testing requirements in part 199 of this subchapter do not apply to the transportation of a hazardous liquid in a gravity line. (c) Exceptions. (1) This section does not apply to those gathering lines that are otherwise excepted under § 195.1(b)(3), (7), (8), (9), or (10). (2) The reporting requirements in §§ 195.52, 195.61, and 195.65 do not apply to the transportation of a hazardous liquid in a gathering line that is specified in paragraph (a) of this section. (3) The drug and alcohol testing requirements in part 199 of this subchapter do not apply to the transportation of a hazardous liquid in a gathering line that is specified in paragraph (a) of this section. ■ 7. Add § 195.65 to subpart B to read as follows: § 195.65 Safety data sheets. 6. Add § 195.15 to subpart A to read as follows: (a) Each owner or operator of a hazardous liquid pipeline facility, following an accident involving a pipeline facility that results in a hazardous liquid spill, must provide safety data sheets on any spilled hazardous liquid to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. (b) Definitions. In this section: (1) Federal On-Scene Coordinator. The term ‘‘Federal On-Scene Coordinator’’ has the meaning given such term in section 311(a) of the Federal Water Pollution Control Act (33 U.S.C. 1321(a)). (2) National Response Center. The term ‘‘National Response Center’’ means the center described under 40 CFR 300.125(a). (3) Safety data sheet. The term ‘‘safety data sheet’’ means a safety data sheet required under 29 CFR 1910.1200. ■ 8. Revise § 195.120 to read as follows: § 195.15 What requirements apply to reporting-regulated-only gathering lines? § 195.120 devices. (a) Scope. Gathering lines that do not otherwise meet the definition of a regulated rural gathering line in § 195.11 and any gathering line not already covered under § 195.1(a)(1), (2), (3) or (4) must comply with the reporting requirements of subpart B of this part. (b) Implementation period—(1) Annual reporting. Operators must comply with the annual reporting requirements in subpart B of this part by March 31, 2021. (2) Accident and safety-related condition reporting. Operators must comply with the accident and safetyrelated condition reporting requirements in subpart B of this part by January 1, 2021. (a) General. Except as provided in paragraphs (b) and (c) of this section, each new pipeline and each main line section of a pipeline where the line pipe, valve, fitting or other line component is replaced must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102 (incorporated by reference, see § 195.3). (b) Exceptions. This section does not apply to: (1) Manifolds; (2) Station piping such as at pump stations, meter stations, or pressure reducing stations; ■ PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 E:\FR\FM\01OCR3.SGM Passage of internal inspection 01OCR3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations (3) Piping associated with tank farms and other storage facilities; (4) Cross-overs; (5) Pipe for which an instrumented internal inspection device is not commercially available; and (6) Offshore pipelines, other than lines 10 inches (254 millimeters) or greater in nominal diameter, that transport liquids to onshore facilities. (c) Impracticability. An operator may file a petition under § 190.9 for a finding that the requirements in paragraph (a) of this section should not be applied to a pipeline for reasons of impracticability. (d) Emergencies. An operator need not comply with paragraph (a) of this section in constructing a new or replacement segment of a pipeline in an emergency. Within 30 days after discovering the emergency, the operator must file a petition under § 190.9 for a finding that requiring the design and construction of the new or replacement pipeline segment to accommodate passage of instrumented internal inspection devices would be impracticable as a result of the emergency. If PHMSA denies the petition, within 1 year after the date of the notice of the denial, the operator must modify the new or replacement pipeline segment to allow passage of instrumented internal inspection devices. ■ 9. Revise § 195.134 to read as follows: jbell on DSK3GLQ082PROD with RULES3 § 195.134 Leak detection. (a) Scope. This section applies to each hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid). (b) General. (1) For each pipeline constructed prior to October 1, 2019. Each pipeline must have a system for detecting leaks that complies with the requirements in § 195.444 by October 1, 2024. (2) For each pipeline constructed on or after October 1, 2019. Each pipeline must have a system for detecting leaks that complies with the requirements in § 195.444 by October 1, 2020. (c) CPM leak detection systems. A new computational pipeline monitoring (CPM) leak detection system or replaced component of an existing CPM system must be designed in accordance with the requirements in section 4.2 of API RP 1130 (incorporated by reference, see § 195.3) and any other applicable design criteria in that standard. (d) Exception. The requirements of paragraph (b) of this section do not apply to offshore gathering or regulated rural gathering lines. ■ 10. In § 195.401, add paragraph (b)(3) to read as follows. VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 § 195.401 General requirements. * * * * * (b) * * * (3) Prioritizing repairs. An operator must consider the risk to people, property, and the environment in prioritizing the correction of any conditions referenced in paragraphs (b)(1) and (2) of this section. * * * * * ■ 11. Add § 195.414 to read as follows: § 195.414 Inspections of pipelines in areas affected by extreme weather and natural disasters. (a) General. Following an extreme weather event or natural disaster that has the likelihood of damage to infrastructure by the scouring or movement of the soil surrounding the pipeline, such as a named tropical storm or hurricane; a flood that exceeds the river, shoreline, or creek high-water banks in the area of the pipeline; a landslide in the area of the pipeline; or an earthquake in the area of the pipeline, an operator must inspect all potentially affected pipeline facilities to detect conditions that could adversely affect the safe operation of that pipeline. (b) Inspection method. An operator must consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the initial inspection to determine the extent of any damage and the need for the additional assessments required under paragraph (a) of this section. (c) Time period. The inspection required under paragraph (a) of this section must commence within 72 hours after the cessation of the event, defined as the point in time when the affected area can be safely accessed by the personnel and equipment required to perform the inspection as determined under paragraph (b) of this section. In the event that the operator is unable to commence the inspection due to the unavailability of personnel or equipment, the operator must notify the appropriate PHMSA Region Director as soon as practicable. (d) Remedial action. An operator must take prompt and appropriate remedial action to ensure the safe operation of a pipeline based on the information obtained as a result of performing the inspection required under paragraph (a) of this section. Such actions might include, but are not limited to: (1) Reducing the operating pressure or shutting down the pipeline; (2) Modifying, repairing, or replacing any damaged pipeline facilities; PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 52295 (3) Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-way; (4) Performing additional patrols, surveys, tests, or inspections; (5) Implementing emergency response activities with Federal, State, or local personnel; and (6) Notifying affected communities of the steps that can be taken to ensure public safety. ■ 12. Add § 195.416 to read as follows: § 195.416 Pipeline assessments. (a) Scope. This section applies to onshore line pipe that can accommodate inspection by means of in-line inspection tools and is not subject to the integrity management requirements in § 195.452. (b) General. An operator must perform an initial assessment of each of its pipeline segments by October 1, 2029, and perform periodic assessments of its pipeline segments at least once every 10 calendar years from the year of the prior assessment or as otherwise necessary to ensure public safety or the protection of the environment. (c) Method. Except as specified in paragraph (d) of this section, an operator must perform the integrity assessment for the range of relevant threats to the pipeline segment by the use of an appropriate in-line inspection tool(s). When performing an assessment using an in-line inspection tool, an operator must comply with § 195.591. An operator must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or other equivalent methods for determining uncertainties) in identifying anomalies. If this is impracticable based on operational limits, including operating pressure, low flow, and pipeline length or availability of in-line inspection tool technology for the pipe diameter, then the operator must perform the assessment using the appropriate method(s) in paragraphs (c)(1), (2), or (3) of this section for the range of relevant threats being assessed. The methods an operator selects to assess low-frequency electric resistance welded pipe, pipe with a seam factor less than 1.0 as defined in § 195.106(e) or lap-welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies. The following alternative assessment methods may be used as specified in this paragraph: (1) A pressure test conducted in accordance with subpart E of this part; E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 52296 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations (2) External corrosion direct assessment in accordance with § 195.588; or (3) Other technology in accordance with paragraph (d). (d) Other technology. Operators may elect to use other technologies if the operator can demonstrate the technology can provide an equivalent understanding of the condition of the line pipe for threat being assessed. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 90 days before conducting the assessment by: (1) Sending the notification, along with the information required to demonstrate compliance with this paragraph, to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590; or (2) Sending the notification, along with the information required to demonstrate compliance with this paragraph, to the Information Resources Manager by facsimile to (202) 366–7128. (3) Prior to conducting the ‘‘other technology’’ assessments, the operator must receive a notice of ‘‘no objection’’ from the PHMSA Information Services Manager or Designee. (e) Data analysis. A person qualified by knowledge, training, and experience must analyze the data obtained from an assessment performed under paragraph (b) of this section to determine if a condition could adversely affect the safe operation of the pipeline. Operators must consider uncertainties in any reported results (including tool tolerance) as part of that analysis. (f) Discovery of condition. For purposes of § 195.401(b)(1), discovery of a condition occurs when an operator has adequate information to determine that a condition presenting a potential threat to the integrity of the pipeline exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to make that determination required under paragraph (e) of this section, unless the operator can demonstrate the 180-day interval is impracticable. If the operator believes that 180 days are impracticable to make a determination about a condition found during an assessment, the pipeline operator must notify PHMSA and provide an expected date when adequate information will become available. This notification must be made in accordance with § 195.452 (m). (g) Remediation. An operator must comply with the requirements in § 195.401 if a condition that could adversely affect the safe operation of a VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 pipeline is discovered in complying with paragraphs (e) and (f) of this section. (h) Consideration of information. An operator must consider all relevant information about a pipeline in complying with the requirements in paragraphs (a) through (g) of this section. ■ 13. Revise § 195.444 to read as follows: first column of the following table no later than the date in the second column: § 195.444 * Leak detection. (a) Scope. Except for offshore gathering and regulated rural gathering pipelines, this section applies to all hazardous liquid pipelines transporting liquid in single phase (without gas in the liquid). (b) General. A pipeline must have an effective system for detecting leaks in accordance with §§ 195.134 or 195.452, as appropriate. An operator must evaluate the capability of its leak detection system to protect the public, property, and the environment and modify it as necessary to do so. At a minimum, an operator’s evaluation must consider the following factors— length and size of the pipeline, type of product carried, the swiftness of leak detection, location of nearest response personnel, and leak history. (c) CPM leak detection systems. Each computational pipeline monitoring (CPM) leak detection system installed on a hazardous liquid pipeline must comply with API RP 1130 (incorporated by reference, see § 195.3) in operating, maintaining, testing, record keeping, and dispatcher training of the system. ■ 14. Amend § 195.452 by: ■ a. Revising paragraphs (a)(3) and (b)(1), the introductory text of paragraph (c)(1)(i), paragraphs (c)(1)(i)(A), (d), (e)(1)(vii), and (g), the introductory text of paragraph (h)(1), and paragraph (h)(2); ■ b. Amending paragraph (i)(2)(viii) by removing the period at the end of the sentence and adding in its place a ‘‘;’’. ■ c. Adding paragraph (i)(2)(ix); ■ d. Revising paragraph (j)(2); ■ e. Adding paragraphs (n) and (o). The revisions and additions read as follows: § 195.452 Pipeline integrity management in high consequence areas. (a) * * * (3) Category 3 includes pipelines constructed or converted after May 29, 2001, and low-stress pipelines in rural areas under § 195.12. * * * * * (b) * * * (1) Develop a written integrity management program that addresses the risks on each segment of pipeline in the PO 00000 Frm 00038 Fmt 4701 Sfmt 4700 Pipeline Date Category 1 Category 2 Category 3 March 31, 2002. February 18, 2003. Date the pipeline begins operation or as provided in § 195.12 for low stress pipelines in rural areas. * * * * (c) * * * (1) * * * (i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by in-line inspection tool(s) described in paragraph (c)(1)(i)(A) of this section for the range of relevant threats to the pipeline segment. If it is impracticable based upon the construction of the pipeline (e.g., diameter changes, sharp bends, and elbows) or operational limits including operating pressure, low flow, pipeline length, or availability of in-line inspection tool technology for the pipe diameter, then the operator must use the appropriate method(s) in paragraphs (c)(1)(i)(B), (C), or (D) of this section for the range of relevant threats to the pipeline segment. The methods an operator selects to assess low-frequency electric resistance welded pipe, pipe with a seam factor less than 1.0 as defined in § 195.106(e) or lap-welded pipe susceptible to longitudinal seam failure, must be capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies. (A) In-line inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges, and grooves. For pipeline segments with an identified or probable risk or threat related to cracks (such as at pipe body or weld seams) based on the risk factors specified in paragraph (e), an operator must use an in-line inspection tool or tools capable of detecting crack anomalies. When performing an assessment using an inline inspection tool, an operator must comply with § 195.591. An operator using this method must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or equivalent for determining uncertainties) in identifying anomalies; * * * * * (d) When must operators complete baseline assessments? (1) All pipelines. An operator must complete the baseline assessment before a new or conversion-to-service pipeline E:\FR\FM\01OCR3.SGM 01OCR3 jbell on DSK3GLQ082PROD with RULES3 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations begins operation through the development of procedures, identification of high consequence areas, and pressure testing of couldaffect high consequence areas in accordance with § 195.304. (2) Newly identified areas. If an operator obtains information (whether from the information analysis required under paragraph (g) of this section, Census Bureau maps, or any other source) demonstrating that the area around a pipeline segment has changed to meet the definition of a high consequence area (see § 195.450), that area must be incorporated into the operator’s baseline assessment plan within 1 year from the date that the information is obtained. An operator must complete the baseline assessment of any pipeline segment that could affect a newly identified high consequence area within 5 years from the date an operator identifies the area. * * * * * (e) * * * (1) * * * (vii) Local environmental factors that could affect the pipeline (e.g., seismicity, corrosivity of soil, subsidence, climatic); * * * * * (g) What is an information analysis? In periodically evaluating the integrity of each pipeline segment (see paragraph (j) of this section), an operator must analyze all available information about the integrity of its entire pipeline and the consequences of a possible failure along the pipeline. Operators must continue to comply with the data integration elements specified in § 195.452(g) that were in effect on October 1, 2018, until October 1, 2022. Operators must begin to integrate all the data elements specified in this section starting October 1, 2020, with all attributes integrated by October 1, 2022. This analysis must: (1) Integrate information and attributes about the pipeline that include, but are not limited to: (i) Pipe diameter, wall thickness, grade, and seam type; (ii) Pipe coating, including girth weld coating; (iii) Maximum operating pressure (MOP) and temperature; (iv) Endpoints of segments that could affect high consequence areas (HCAs); (v) Hydrostatic test pressure including any test failures or leaks—if known; (vi) Location of casings and if shorted; (vii) Any in-service ruptures or leaks—including identified causes; (viii) Data gathered through integrity assessments required under this section; (ix) Close interval survey (CIS) survey results; VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 (x) Depth of cover surveys; (xi) Corrosion protection (CP) rectifier readings; (xii) CP test point survey readings and locations; (xiii) AC/DC and foreign structure interference surveys; (xiv) Pipe coating surveys and cathodic protection surveys. (xv) Results of examinations of exposed portions of buried pipelines (i.e., pipe and pipe coating condition, see § 195.569); (xvi) Stress corrosion cracking (SCC) and other cracking (pipe body or weld) excavations and findings, including insitu non-destructive examinations and analysis results for failure stress pressures and cyclic fatigue crack growth analysis to estimate the remaining life of the pipeline; (xvii) Aerial photography; (xviii) Location of foreign line crossings; (xix) Pipe exposures resulting from repairs and encroachments; (xx) Seismicity of the area; and (xxi) Other pertinent information derived from operations and maintenance activities and any additional tests, inspections, surveys, patrols, or monitoring required under this part. (2) Consider information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage prevention activities, and development or planned development along the pipeline; (3) Consider how a potential failure would affect high consequence areas, such as location of a water intake. (4) Identify spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings; evidence of pipeline damage where aerial photography shows evidence of encroachment). Storing the information in a geographic information system (GIS), alone, is not sufficient. An operator must analyze for interrelationships among the data. (h) * * * (1) General requirements. An operator must take prompt action to address all anomalous conditions in the pipeline that the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline’s integrity, as required by this part. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An operator must comply with PO 00000 Frm 00039 Fmt 4701 Sfmt 4700 52297 all other applicable requirements in this part in remediating a condition. Each operator must, in repairing its pipeline systems, ensure that the repairs are made in a safe and timely manner and are made so as to prevent damage to persons, property, or the environment. The calculation method(s) used for anomaly evaluation must be applicable for the range of relevant threats. * * * * * (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information to determine that a condition presenting a potential threat to the integrity of the pipeline exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate the 180-day interval is impracticable. If the operator believes that 180 days are impracticable to make a determination about a condition found during an assessment, the pipeline operator must notify PHMSA in accordance with paragraph (m) of this section and provide an expected date when adequate information will become available. * * * * * (i) * * * (2) * * * (ix) Seismicity of the area. * * * * * (j) * * * (2) Verifying covered segments. An operator must verify the risk factors used in identifying pipeline segments that could affect a high consequence area on at least an annual basis not to exceed 15 months (Appendix C of this part provides additional guidance on factors that can influence whether a pipeline segment could affect a high consequence area). If a change in circumstance indicates that the prior consideration of a risk factor is no longer valid or that an operator should consider new risk factors, an operator must perform a new integrity analysis and evaluation to establish the endpoints of any previously identified covered segments. The integrity analysis and evaluation must include consideration of the results of any baseline and periodic integrity assessments (see paragraphs (b), (c), (d), and (e) of this section), information analyses (see paragraph (g) of this section), and decisions about remediation and preventive and mitigative actions (see paragraphs (h) and (i) of this section). An operator must complete the first annual verification E:\FR\FM\01OCR3.SGM 01OCR3 52298 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES3 under this paragraph no later than July 1, 2021. * * * * * (n) Accommodation of instrumented internal inspection devices— (1) Scope. This paragraph does not apply to any pipeline facilities listed in § 195.120(b). (2) General. An operator must ensure that each pipeline is modified to accommodate the passage of an instrumented internal inspection device by July 2, 2040. (3) Newly identified areas. If a pipeline could affect a newly identified high consequence area (see paragraph (d)(2) of this section) after July 2, 2035, an operator must modify the pipeline to accommodate the passage of an instrumented internal inspection device within 5 years of the date of identification or before performing the baseline assessment, whichever is sooner. (4) Lack of accommodation. An operator may file a petition under § 190.9 of this chapter for a finding that the basic construction (i.e., length, diameter, operating pressure, or location) of a pipeline cannot be VerDate Sep<11>2014 18:36 Sep 30, 2019 Jkt 250001 modified to accommodate the passage of an instrumented internal inspection device or that the operator determines it would abandon or shut-down a pipeline as a result of the cost to comply with the requirement of this section. (5) Emergencies. An operator may file a petition under § 190.9 of this chapter for a finding that a pipeline cannot be modified to accommodate the passage of an instrumented internal inspection device as a result of an emergency. An operator must file such a petition within 30 days after discovering the emergency. If the petition is denied, the operator must modify the pipeline to allow the passage of an instrumented internal inspection device within 1 year after the date of the notice of the denial. ■ 15. Add § 195.454 to Subpart F to read as follows: § 195.454 Integrity assessments for certain underwater hazardous liquid pipeline facilities located in high consequence areas. Notwithstanding any pipeline integrity management program or integrity assessment schedule otherwise required under § 195.452, each operator of any underwater hazardous liquid PO 00000 Frm 00040 Fmt 4701 Sfmt 9990 pipeline facility located in a high consequence area that is not an offshore pipeline facility and any portion of which is located at depths greater than 150 feet under the surface of the water must ensure that: (a) Pipeline integrity assessments using internal inspection technology appropriate for the integrity threats to the pipeline are completed not less often than once every 12 months, and; (b) Pipeline integrity assessments using pipeline route surveys, depth of cover surveys, pressure tests, external corrosion direct assessment, or other technology that the operator demonstrates can further the understanding of the condition of the pipeline facility, are completed on a schedule based on the risk that the pipeline facility poses to the high consequence area in which the pipeline facility is located. Issued in Washington, DC, on September 17, 2019, under authority delegated in 49 CFR part 1.97. Howard R. Elliott, Administrator. [FR Doc. 2019–20458 Filed 9–30–19; 8:45 am] BILLING CODE 4910–60–P E:\FR\FM\01OCR3.SGM 01OCR3

Agencies

[Federal Register Volume 84, Number 190 (Tuesday, October 1, 2019)]
[Rules and Regulations]
[Pages 52260-52298]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-20458]

[[Page 52259]]

Vol. 84

Tuesday,

No. 190

October 1, 2019

Part III

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Part 195

Pipeline Safety: Safety of Hazardous Liquid Pipelines; Final Rule

Federal Register / Vol. 84 , No. 190 / Tuesday, October 1, 2019 /
Rules and Regulations

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 195

[Docket No. PHMSA-2010-0229; Amdt. No. 195-102]
RIN 2137-AE66

Pipeline Safety: Safety of Hazardous Liquid Pipelines

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).

ACTION: Final rule.

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SUMMARY: In response to congressional mandates, NTSB and GAO
recommendations, lessons learned, and public input, PHMSA is amending
the Pipeline Safety Regulations to improve the safety of pipelines
transporting hazardous liquids. Specifically, PHMSA is extending
reporting requirements to certain hazardous liquid gravity and rural
gathering lines; requiring the inspection of pipelines in areas
affected by extreme weather and natural disasters; requiring integrity
assessments at least once every 10 years of onshore hazardous liquid
pipeline segments located outside of high consequence areas and that
are ``piggable'' (i.e., can accommodate in-line inspection devices);
extending the required use of leak detection systems beyond high
consequence areas to all regulated, non-gathering hazardous liquid
pipelines; and requiring that all pipelines in or affecting high
consequence areas be capable of accommodating in-line inspection tools
within 20 years, unless the basic construction of a pipeline cannot be
modified to permit that accommodation. Additionally, PHMSA is
clarifying other regulations and is incorporating Sections 14 and 25 of
the PIPES Act of 2016 to improve regulatory certainty and compliance.

DATES: The effective date of this final rule is July 1, 2020. The
incorporation by reference of certain publications listed in the rule
was approved by the Director of the Federal Register as of March 24,
2017 and March 6, 2015.

FOR FURTHER INFORMATION CONTACT:
Technical questions: Steve Nanney, Project Manager, by telephone at
713-272-2855.
General information: Robert Jagger, Senior Transportation
Specialist, by telephone at 202-366-4361.

SUPPLEMENTARY INFORMATION:

I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the Regulatory Action in
Question
C. Costs and Benefits
II. Background
A. Detailed Overview
B. Pipeline Safety, Regulatory Certainty, and Job Creation Act
of 2011
C. National Transportation Safety Board Recommendations
D. Summary of Each Topic
III. Pipeline Advisory Committee
IV. Analysis of Comments and PHMSA Response
A. Reporting Requirements for Gravity Lines
B. Reporting Requirements for Gathering Lines
C. Pipelines Affected by Extreme Weather and Natural Disasters
D. Periodic Assessment of Pipelines Not Subject to IM
E. IM and Non-IM Repair Criteria
F. Leak Detection Requirements
G. Increased Use of ILI Tools in HCAs
H. Clarifying Other Requirements
V. PIPES Act of 2016
VI. Section-by-Section Analysis
VII. Regulatory Notices

I. Executive Summary

A. Purpose of the Regulatory Action

In recent years, there have been significant hazardous liquid
pipeline accidents, most notably the 2010 crude oil spill near
Marshall, MI, during which at least 843,000 gallons of crude oil were
released, significantly affecting the Kalamazoo River. In response to
accident investigation findings, incident report data and trends, and
stakeholder input, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) is amending the hazardous liquid pipeline safety
regulations to improve protection of the public, property, and the
environment by closing regulatory gaps where appropriate and ensuring
that operators are increasing the detection and remediation of pipeline
integrity threats, and mitigating the adverse effects of pipeline
failures. On October 18, 2010, PHMSA published an Advanced Notice of
Proposed Rulemaking (ANPRM) in the Federal Register (75 FR 63774). The
ANPRM solicited stakeholder and public input and comments on several
aspects of the hazardous liquid pipeline regulations being considered
for revision or updating to address various pipeline safety issues.
Subsequently, Congress enacted the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (2011 Pipeline
Safety Act). That legislation included several provisions that are
relevant to the regulation of hazardous liquid pipelines. The 2011
Pipeline Safety Act included mandates for PHMSA to complete studies on
topics including existing Federal and State regulations for gathering
lines, on automatic shutdown and remote control valves, expanding
integrity management requirements beyond high-consequence areas, and on
the leak detection systems used by hazardous liquid operators. PHMSA
completed these studies and submitted the valve and leak detection
studies to Congress on December 27, 2012; the gathering line study to
Congress on May 8, 2015; and the integrity management (IM) study in
April of 2016. These studies are available in the docket for this
rulemaking.
Shortly after the 2011 Pipeline Safety Act was passed, the National
Transportation Safety Board (NTSB) issued its accident investigation
report on the Marshall, MI, accident on July 10, 2012. In it, the NTSB
made recommendations regarding the need to revise and update hazardous
liquid pipeline regulations. Specifically, the NTSB issued
recommendations P-12-03 and P-12-04, which addressed detection of
pipeline cracks and ``discovery of condition,'' respectively. The
``discovery of condition'' recommendation would require, in cases where
a determination about pipeline threats has not been obtained within 180
days following the date of inspection, that pipeline operators notify
PHMSA and provide an expected date when adequate information will
become available.
The Government Accounting Office (GAO) also issued a recommendation
in 2012 concerning hazardous liquid and gas gathering pipelines.
Recommendation GAO-12-388, dated March 22, 2012, states, ``To enhance
the safety of unregulated onshore hazardous liquid and gas gathering
pipelines, the Secretary of Transportation should direct the PHMSA
Administrator to collect data from operators of federally unregulated
onshore hazardous liquid and gas gathering pipelines, subsequent to an
analysis of the benefits and industry burdens associated with such data
collection.''
On October 13, 2015, PHMSA published a NPRM to seek public comments
on proposed changes to the hazardous liquid pipeline safety regulations
(80 FR 61609). A summary of those proposed changes is provided later in
this document.
Between the publication of the NPRM and this final rule, the
President signed the ``Protecting our Infrastructure of Pipelines and
Enhancing Safety Act of 2016'' (PIPES Act of 2016), Public Law 114-183,
on June 22, 2016. While the PIPES Act of 2016 contained several
mandates that must be addressed

[[Page 52261]]

through rulemaking, certain provisions are self-executing standards
that can be incorporated into this final rule rulemaking without a
prior NPRM and opportunity to comment. Those changes are outlined in
Section V of this document.

B. Summary of the Major Provisions of the Regulatory Action

In response to these mandates, recommendations, lessons learned,
and public input, PHMSA is making certain amendments to the Pipeline
Safety Regulations affecting hazardous liquid pipelines. The first and
second amendments extend reporting requirements to certain hazardous
liquid gravity and rural gathering lines not currently regulated by
PHMSA. The collection of information about these lines, including those
that are not currently regulated, is authorized under the Pipeline
Safety Laws, and the resulting data will assist in determining whether
the existing Federal and State regulations for these lines and the
scope of their applicability are adequate.
The third amendment requires inspections of pipelines in areas
affected by extreme weather or natural disasters that could impose
unexpected longitudinal or circumferential pipe loads, or other risks
to the pipeline's integrity and continued safe operation. This
provision affects all covered lines under Sec. 195.1, whether they be
onshore or offshore, and in a high consequence area (HCA) or outside an
HCA.\1\ Such inspections will help to ensure that operators can safely
operate pipelines after these events.
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\1\ High Consequence Areas are defined in 49 CFR 195.450.
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The fourth amendment requires integrity assessments at least once
every 10 years, using inline inspection tools or other technology, as
appropriate for the threat being assessed, of onshore, piggable,
hazardous liquid pipeline segments located outside of HCAs. Existing
regulations require operators to assess hazardous liquid pipeline
segments located inside HCAs at least once every 5 years. These
assessments will provide important information to operators about the
condition of these pipelines, including the existence of internal and
external corrosion and deformation anomalies.
The fifth amendment extends the required use of leak detection
systems beyond HCAs to all regulated hazardous liquid pipelines, except
for offshore gathering and regulated rural gathering pipelines. The use
of such systems will help to mitigate the effects of hazardous liquid
pipeline failures that occur outside of HCAs.
The sixth amendment requires that all pipelines in or affecting
HCAs be capable of accommodating in-line inspection tools within 20
years, unless the basic construction of a pipeline cannot be modified
to permit that accommodation. In-line inspection tools are an effective
means of assessing the integrity of a pipeline and broadening their use
will improve the detection of anomalies and prevent or mitigate future
accidents in high-risk areas. Finally, PHMSA is clarifying other
regulations and is incorporating Sections 14 and 25 of the PIPES Act of
2016 to improve regulatory certainty and compliance.

C. Cost and Benefits

Consistent with Executive Orders 12866 and 13563, PHMSA has
prepared an assessment of the benefits and costs of the rule as well as
reasonably feasible alternatives. PHMSA estimates that up to 502
hazardous liquid operators may incur costs to comply with the NPRM. The
estimated annual costs for individual components of the requirements in
this rulemaking range between approximately $5,000 and $10.5 million,
with aggregate costs of approximately $19.5 million to $21.4 million
for all requirements.\2\
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\2\ Estimated costs are annualized using a 7 percent discount
rate.
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This final rule is primarily designed to mitigate or prevent
hazardous liquid pipeline incidents, and is expected to reduce pipeline
incident damages, including injuries and fatalities, cleanup and
response costs, property damage, product loss, and ecosystem impacts.
The rule's information reporting requirements are designed to provide
PHMSA information to inform regulatory decision-making. The Regulatory
Impact Analysis (RIA) for this final rule is available in the docket.
The table below provides a summary of the estimated costs and benefits
for each of the eight major provisions and in total (see the RIA for
the details of these estimates).

Annualized Costs and Benefits by Requirement Area (2017$) \3\
----------------------------------------------------------------------------------------------------------------
Annual costs \1\
Final rule requirement area -------------------------------------------------------- Benefits
3% discount rate 7% discount rate
----------------------------------------------------------------------------------------------------------------
1. Reporting requirements for $5,000.................... $5,000.................... Better risk
gravity lines. understanding and
management.\2\
2. Reporting requirements for $75,000................... $76,000................... Better risk
gathering lines. understanding and
management.\3\
3. Inspections of pipelines in Minimal................... Minimal................... Additional clarity and
areas affected by extreme certainty for pipeline
weather events or natural operators.
disasters \4\.
4. Assessments of onshore $6,467,000................ $6,467,000................ Avoided incidents and
pipelines that are not already damages through
covered under the IM program detection of safety
using ILI every 10 years 5 6. conditions.\7\
5. IM repair criteria \8\...... $0........................ $0........................ $0.
6. LDSs on pipelines located $8,652,000................ $10,508,000............... Reduced damages through
outside HCAs \6\. earlier detection and
response.\9\
7. Increased use of ILI tools Minimal................... Minimal................... Improved detection of
\10\. pipeline flaws.\10\
8. Clarify certain IM plan $4,269,000................ $4,343,000................ Reduced damages through
requirements. prevention and earlier
detection and
response.\11\
--------------------------------------------------------------------------------
Total...................... $19,468,000............... $21,399,000............... Reduced damages from
avoiding and/or
mitigating hazardous
liquid releases.
----------------------------------------------------------------------------------------------------------------
\1\ Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in
individual sections of the document. One-time costs are annualized over a 10-year period using discount rates
of 3 percent and 7 percent.
\2\ Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow
pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of
this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated
gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
101 gallons per year to generate benefits that equal the costs.

[[Page 52262]]

\3\ The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated
gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
1,493 gallons per year to generate benefits that equal the costs.
\4\ To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting
inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not
reflected in this analysis.
\5\ PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not
currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios:
(1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a
scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two
scenarios are $0 and $12.9 million, respectively.
\6\ Excludes gathering lines.
\7\ Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to
prevent 12 incidents for benefits to equate costs.
\8\ PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or
benefits.
\9\ As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an
average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of
approximately $382,179, not including additional damages and costs that are excluded or underreported in the
incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents.
\10\ Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the
extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be
minimal due to baseline prevalence of ILI-capable pipelines in all areas.
\11\ The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids
cannot be quantified but could vary in frequency and size depending on the types of failures that are averted.
Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected
to enhance an operator's ability to identify and address risk. The societal costs associated with incidents
involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates
for this requirement are equivalent to the average damages from less than three such incidents. This is
relative to an annual average of 161 incidents in HCAs between 2010 and 2017.

II. Background
---------------------------------------------------------------------------

\3\ Numbers in this table may not sum due to rounding.
---------------------------------------------------------------------------

A. Detailed Overview

This final rule addresses the requirements established by Congress
in the 2011 Pipeline Safety Act, which are consistent with the emerging
needs of the Nation's hazardous liquid pipeline system. This final rule
also advances an important safety need to adapt and expand risk-based
safety practices considering changing markets and a growing national
population whose location choices are in ever-closer proximity to
existing pipelines.
This final rule strengthens protocols for IM, including protocols
for inspections, and improves and streamlines information collection to
help drive risk-based identification of the areas with the greatest
safety deficiencies.
Hazardous Liquid Infrastructure Overview
There are two major types of pipelines along the petroleum
transportation route: Gathering pipeline systems, and crude oil and
refined products pipeline systems. The location, construction and
operation of these systems are generally regulated by Federal and State
requirements.
Gathering lines are typically smaller pipelines no more than 8\5/8\
inches in diameter that transport petroleum from onshore and offshore
production facilities. Hazardous liquid pipelines transport the crude
oil from the gathering systems to refineries and from refineries to
distribution centers. Hazardous liquid lines transport both crude and
refined products, and can be hundreds of miles long. These lines may
cross State and continental borders, and range in size from 2 to 48
inches in diameter. Hazardous liquid pipeline networks also include
pump stations, which move the product through the pipelines, and
storage terminals. Changes in product demand has also led to efforts by
operators to increase pipeline capacity through flow-direction
reversals or converting natural gas pipelines into hazardous liquid
pipelines.
Per PHMSA's database, 43 percent of all hazardous liquid pipelines
were installed prior to 1970.\4\ However, pipeline manufacturing,
construction, and operational and maintenance practices have been
improving steadily in recent decades, and some older pipes are
susceptible to certain manufacturing or construction defects. For
example, low-frequency electric resistance welded (ERW) pipe used from
the early 1900s through the post-World War II construction boom that
lasted well into the 1970s is vulnerable to seam-quality issues. Since
the early 1970s, many improvements in pipe manufacturing and materials
have been made, and steel and seam properties of pipe have improved
with the increased use of high-frequency electric welded (HF-ERW),
submerged arc welded (SAW), and seamless pipe (SMLS).\5\ In addition,
smart pigs, which are tools that record information about the internal
conditions of a pipeline, were not developed until the 1960s and 1970s
prior to the adoption of the part 195 regulations.
---------------------------------------------------------------------------

\4\ PHMSA's Annual Report Mileage for Hazardous Liquid or Carbon
Dioxide Systems; https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\5\ HF-ERW steel pipe has a welded pipe seam made using a high
frequency welding current. SMLS steel pipe has no longitudinal weld
seam. SAW steel pipe has a weld seam made using a submerged welding
arc in a bed of powdered flux to shield it from impurities.
---------------------------------------------------------------------------

Since 2012, U.S. oil production has increased about 70 percent from
approximately 2.4 to 3.4 Billion barrels annually \6\ resulting in the
United States becoming the world's largest producer of liquid fuels in
early 2014. Much of the recent increases in production have been in
tight oil plays. Tight oil shale formations are heterogeneous and vary
widely over relatively short distances and are subjected to fracking.
Examples of tight oil formations include the Bakken Shale, the Niobrara
Formation, Barnett Shale, and the Eagle Ford Shale in the United
States. Per data from the U.S. Energy Information Administration (EIA),
in 2017, tight oil plays accounted for approximately half of the U.S.
production, balancing declining production in older plays. While tight
oil from shale plays has historically been more difficult to extract,
improvements in drilling and production methods, such as horizontal
drilling and hydraulic fracturing, have made it economically
recoverable. These tight oil plays are located both in regions that
have had an oil extraction industry for decades and new regions, such
as the Bakken region in North Dakota and Montana, that were not
previously oil-producing areas. This has expanded U.S. refiners' access
to domestically produced crudes, and U.S. crude oil imports dropped by
7 percent since 2012.\7\ Additionally, exports have risen from minimal
amounts in 2012 to

[[Page 52263]]

over a million barrels per day in 2017.\8\ These supply increases and
spatial changes in production patterns are creating wide-ranging
impacts on liquid fuels transportation infrastructure.
---------------------------------------------------------------------------

\6\ U.S. Energy Information Administration, Crude Oil
Production. Producers extracted 2.4 billion barrels of crude oil
from U.S. fields in 2012 and 3.4 billion barrels of crude oil in
2017. https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm.
\7\ EIA, U.S. Imports of Crude Oil (Thousands of Barrels per
Day). https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbblpd_a.htm.
\8\ EIA, U.S. Exports of Crude Oil (Thousand Barrels per Day).
https://www.eia.gov/dnav/pet/pet_move_exp_dc_NUS-Z00_mbblpd_a.htm.
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Regulatory History
Congress established the current framework for regulating the
safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline
Safety Act (HLPSA) of 1979 (Pub. L. 96-129). The HLPSA provides the
Secretary of Transportation (the Secretary) with the authority to
prescribe minimum Federal safety standards for hazardous liquid
pipeline facilities. That authority, as amended in subsequent
reauthorizations, is currently codified in the Pipeline Safety Laws (49
U.S.C. 60101, et seq.).
PHMSA is the agency within DOT that administers the Pipeline Safety
Laws. PHMSA has issued a set of comprehensive safety standards for the
design, construction, testing, operation, and maintenance of hazardous
liquid pipelines. Those standards are codified in the Hazardous Liquid
Pipeline Safety Regulations (49 CFR part 195).
Part 195 applies broadly to the transportation of hazardous liquids
or carbon dioxide by pipeline, including on the Outer Continental
Shelf, with certain exceptions set forth by statute or regulation. A
combination of prescriptive and management-based safety standards is
used (i.e., an objective is specified, but the method of achieving that
objective is not). Risk management principles play a key role in the IM
requirements.
PHMSA exercises primary regulatory authority over interstate
hazardous liquid pipelines, and the owners and operators of those
facilities must comply with safety standards in part 195. States may
apply to PHMSA for a certification to conduct inspections of intrastate
hazardous liquid pipelines. Public utility commissions administer most
State pipeline safety programs. These State authorities must adopt the
Pipeline Safety Regulations as part of a certification or agreement
with PHMSA, but may establish more stringent safety standards for
intrastate pipeline facilities within their State regulatory
authorities. PHMSA is precluded from regulating the safety standards or
practices for an intrastate pipeline facility if a State is currently
certified to regulate that facility. States certified to regulate their
intrastate lines can also enter into agreements with PHMSA to serve as
an agent for inspecting interstate facilities, and they can receive
Federal monetary grants to off-set the costs of those State
inspections.
In 2000 and 2002, the Office of Pipeline Safety (OPS) published
regulations requiring IM programs for hazardous liquid pipeline
operators in response to a hazardous liquid incident in Bellingham, WA,
in 1999 that killed three people.\9\ The regulations were broad-
reaching and supplemented PHMSA's prescriptive safety requirements with
performance and process-oriented requirements. The approach aimed to
set expectations for operators while giving them a degree of
flexibility in how they complied with those expectations. The
objectives of the IM regulations were to accelerate and improve the
quality of integrity assessments conducted on pipelines in areas with
the highest potential for adverse consequences; promote a more
rigorous, integrated, and systematic management of pipeline integrity
and risk by operators; strengthen the government's role in the
oversight of pipeline operator integrity plans and programs; and
increase the public's confidence in the safe operation of the Nation's
pipeline network.
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\9\ 65 FR 75378; December 1, 2000; Pipeline Safety: Pipeline
Integrity Management in High Consequence Areas (Hazardous Liquid
Operators With 500 or More Miles of Pipeline). 67 FR 1650; January
14, 2002; Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Repair Criteria). 67 FR 2136; January 16, 2002;
Pipeline Safety: Pipeline Integrity Management in High Consequence
Areas (Hazardous Liquid Operators With Less Than 500 Miles of
Pipelines).
---------------------------------------------------------------------------

In January 2011, PHMSA published the Hazardous Liquid Integrity
Management Progress Report,\10\ which reported on PHMSA's progress in
achieving the program objectives and examined accident trends. The
report found that the IM rule and PHMSA's rigorous oversight of
operator compliance with the rule are contributing to improved safety
performance, including a reduction in the frequency of significant
accidents and a decrease in volume spilled in significant accidents.
---------------------------------------------------------------------------

\10\ https://primis.phmsa.dot.gov/iim/IM_Jan2011_StatusReport_01_23_11.pdf.
---------------------------------------------------------------------------

PHMSA's Progress on Integrity Management
The original part 195 Pipeline Safety Regulations were not designed
with risk management in mind. In the mid-1990s, following models from
other industries such as nuclear power, PHMSA started to explore
whether a risk-based approach to regulation could improve safety of the
public and the environment. During this time, PHMSA found that many
operators were performing forms of IM that varied in scope and
sophistication but there were not consistent minimum standards or
requirements.
Since the implementation of the IM regulations more than 15 years
ago, many factors have changed. Most importantly, there have been
sweeping changes in the oil industry, and the Nation's relatively safe
but aging pipeline network faces increased pressures from these
changes. Long-identified pipeline safety issues, some of which IM set
out to address, remain problems. Infrequent but severe accidents
indicate that some pipelines continue to be vulnerable to failures
stemming from, among other things, outdated construction methods or
materials. Some severe pipeline accidents have occurred in areas
outside HCAs where the application of IM principles is not
required.\11\
---------------------------------------------------------------------------

\11\ Per PHMSA annual report data accessed May 14, 2019, 1677
non-HCA accidents have occurred since 2010. Of these accidents, 908
resulted in a ``large'' spill, which for reporting purposes is
defined as those spills where there was a fatality, injury, fire,
explosion, water contamination, property damage of greater than
$50,000, or an unintentional loss of product greater than 210
gallons (5 bbls).
---------------------------------------------------------------------------

The current IM program is both a set of regulations and an overall
regulatory approach to improve pipeline operators' ability to identify
and mitigate the risks to their pipeline systems. On the operator
level, an IM program includes adopting procedures and processes to
identify HCAs, which are areas with the greatest population density and
environmental sensitivity; determining likely threats to the pipeline
within the HCA; evaluating the physical integrity of the pipe within
the HCA; and repairing or remediating any pipeline defects found.
Because these procedures and processes are complex and interconnected,
effective implementation of an IM program relies on continual
evaluation and data integration.
Operators have made great progress towards achieving the IM
objectives. Operators have an improved understanding of the precise
locations of their HCAs--those areas where integrity assessments and
other protective measures spelled out in the IM rule must be taken to
assure public safety and environmental protection. During an incident,
petroleum can spread over large areas and cause environmental damage.
The IM protections for HCAs are designed to account for the potential
environmental and community risks from oil releases. Per PHMSA's
hazardous liquid annual

[[Page 52264]]

data, 42 percent of the Nation's hazardous liquid pipelines \12\ can
potentially affect HCAs and thus receive the enhanced level of
integrity assessment and protection mandated by the IM rule. As
required by the IM rule, operators have also conducted baseline
integrity assessments on all pipelines that could affect HCAs and have
begun conducting reassessments of these same pipeline segments. Through
this requirement to assess their pipelines, operators now have an
improved understanding of the condition of pipelines in these safety-
sensitive areas.
---------------------------------------------------------------------------

\12\ https://phmsa.dot.gov/portal/site/PHMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789/?vgnextoid=a872dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2dc110VgnVCM1000009ed07898RCRD&vgnextfmt=print.
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According to PHMSA's January 2011 Hazardous Liquid Integrity
Management Progress Report, which tracked the progress and
effectiveness of the IM program in its first decade, as a result of
these initial baseline assessments, operators have made more than 7,600
repairs of anomalies that required immediate attention, remediated over
28,000 other conditions on a scheduled basis, and addressed an
additional 79,000 anomalies that were not required to be addressed by
the IM rule, thus significantly improving the condition of the Nation's
pipelines.
However, based on recent accidents and mandates from the 2011
Pipeline Safety Act, improvement is still needed in the areas of data
integration and their use in risk modelling, risk analysis, and to
identify and implement additional preventive and mitigative measures to
reduce risk. Improving data integration is critical, as the integrity
assessment provisions of the rule only address some of the causes of
pipeline failures.
Inadequate Leak Detection, Exposure to Weather, Increased Use, and Age
Can Increase the Risk of Pipeline Incidents
Risk factors for pipeline safety issues stem from many sources,
including manufacturing issues, external weather and environmental
factors, land-use activities near pipelines, other operational issues,
and age-related integrity issues.
On July 25, 2010, a segment of a 30-inch-diameter pipeline called
Line 6B, owned and operated by Enbridge Incorporated, ruptured in a
wetland area in Marshall, MI. Per Sec. Sec. 195.450 and 195.6, this
area was identified by the operator as an ``other populated area,''
which meant it was within an HCA. Per the NTSB's Pipeline Accident
Report on the incident, the rupture occurred during the last stages of
a planned shutdown and was not discovered or addressed for over 17
hours. During the time lapse, Enbridge twice pumped additional oil (81
percent of the total release) into Line 6B during two startups; the
total release was estimated by Enbridge to be 843,444 gallons of crude
oil.\13\ The oil saturated the surrounding wetlands and flowed into the
Talmadge Creek and the Kalamazoo River. In all, 4,632 acres of land
were impacted, 346 animals were killed, 4,208 animals were oiled, and
fish and benthic invertebrate communities were impacted. Further,
approximately 100,000 recreational user-days were lost, including
activities like fishing and boating, and general shoreline park and
trail use. The incident also resulted in losses of tribal use, as the
Kalamazoo River is used by two tribes for water travel; subsistence;
and medicinal, economic, educational, and ceremonial services.\14\ This
incident motivated a reexamination of hazardous liquid pipeline safety.
The NTSB made recommendations to PHMSA and the regulated industry
regarding the need to improve hazardous liquid pipeline safety.
Congress also directed PHMSA to reexamine many of its safety
requirements, including the expansion of IM regulations to more
hazardous liquid pipelines. Other recent accidents, including a pair of
related failures that occurred in 2010 on a crude oil pipeline in Salt
Lake City, UT, corroborated the significance of having an adequate
means for identifying and responding to leaks in all locations.
---------------------------------------------------------------------------

\13\ National Transportation Safety Board: ``Enbridge
Incorporated Hazardous Liquid Pipeline Rupture and Release,
Marshall, Michigan, July 25, 2010,'' Accident Report NTSB/PAR-12/01,
adopted 2012; https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf.
\14\ U.S. Fish and Wildlife Service: ``Final Damage Assessment
and Restoration Plan/Environmental Assessment for the July 25-26,
2010 Enbridge Line 6B Oil Discharges near Marshall, MI;'' Sections
1.4--Summary of Natural Resource Injuries and 3.0--Injury Assessment
and Quantification. October 2015. https://www.fws.gov/midwest/es/ec/nrda/MichiganEnbridge/pdf/FinalDARP_EA_EnbridgeOct2015.pdf.
---------------------------------------------------------------------------

The Nation's pipeline system also faces significant risk from
failure due to extreme weather events and natural disasters, such as
hurricanes, floods, mudslides, tornadoes, and earthquakes. On January
17, 2015, a breach in the Bridger Pipeline Company's Poplar system
resulted in a spill into the Yellowstone River near the town of
Glendive, MT, releasing 31,835 gallons (758 barrels) \15\ of crude oil
into the river and affecting local water supplies. Information
indicated over 100 feet of pipeline was exposed on the river bottom,
and the release point was near a girth weld. A depth of cover survey
indicated sufficient cover in late 2011,\16\ but the area experienced
localized flooding in early 2014. A previous crude oil spill into the
Yellowstone River in 2011 near Laurel, MT, was caused by channel
migration and river bottom scour, leaving a large span of the pipeline
exposed to prolonged current forces and debris washing downstream in
the river. Those external forces damaged the exposed pipeline.
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\15\ PHMSA Database: ``Operator Information: Incident and
Mileage Data: Bridger Pipeline LLC,'' https://primis.phmsa.dot.gov/comm/reports/operator/OperatorIM_opid_31878.html?nocache=4851%20-%20_Incidents_tab_3#_OuterPanel_tab_2.
\16\ PHMSA, Corrective Action Order, CPF No. 5-2015-5003H, page
4, January 23, 2015; https://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Pipeline/520155003H_Corrective%20Action%20Order_01232015.pdf.
---------------------------------------------------------------------------

In October 1994, flooding along the San Jacinto River led to the
failure of eight hazardous liquid pipelines and undermined a number of
other pipelines. The escaping products were ignited, leading to 547
people in the area suffering extensive smoke inhalation or burn
injuries.\17\ According to PHMSA's Accident and Incident Data for
hazardous liquid pipelines, from 2010 to 2017, there were 145
reportable incidents \18\ in which storms or other severe natural force
conditions damaged pipelines and resulted in their failure. Operators
reported total damages of over $232 million from these incidents.\19\
PHMSA has issued several Advisory Bulletins to operators warning about
extreme weather events and the consequences of flooding events,
including river scour and river channel migration. Further, in December
2017, the American Petroleum Institute issued a Recommended Practice
1133 that provided guidance to operators on how to identify at-risk
river crossings and take measures to reduce such risks before, during,
and after flooding- and river-scour events.
---------------------------------------------------------------------------

\17\ NTSB, Pipeline Special Investigation Report, ``Evaluation
of Pipeline Failures During Flooding and of Spill Response Actions,
San Jacinto River Near Houston, Texas, October 1994;'' NTSB/SIR-96/
04, Adopted September 6, 1996.
\18\ Reporting thresholds for hazardous liquid pipelines are
established at Sec. 195.50. Operators must report any failures of a
hazardous liquid pipeline resulting in any of the following: (1) An
explosion or fire not intentionally set by the operator, (2) A
release of 5 gallons or more of hazardous liquid or carbon dioxide,
(3) The death of an individual, (4) Personal injury requiring
hospitalization, (5) Estimated property damage exceeding $50,000.
\19\ PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
---------------------------------------------------------------------------

In addition to external weather and environmental threats, changing
production and shipment patterns are increasing stress on the Nation's

[[Page 52265]]

pipeline system. Shifting production to tight oil production like shale
plays have changed U.S. oil production locations, as well as the types
of crude transported in the Nation's pipelines. The U.S. pipeline
system has previously moved crude oil from interior production regions
to the Gulf of Mexico refineries, and petroleum products from Gulf
Coast refineries to the interior of the country. However, increased
tight oil production requires significant infrastructure expansion in
new areas, and shifting production areas are changing the patterns of
oil transport. Many operators are adapting their systems to move crude
oil to markets formerly dependent on imports by modifying existing
pipelines. These modifications can be made by reversing flow directions
and repurposing natural gas pipelines; in some cases pipeline expansion
projects can also increase pumping capability with minimal alterations
of the pipeline itself.
Reversing a pipeline's flow, modifying pump station placement and
operation, changing commodities, or making other changes to a
pipeline's historical hydraulic gradient can impose new stresses on the
system due to altered pressure gradients, cycling, and flow rates.
Furthermore, certain commodities and low flow rates may create new
risks of internal corrosion. Occasional failures on hazardous liquid
pipelines have occurred after operational changes that include flow
reversals and product changes. PHMSA has noticed several recent or
proposed flow reversals and product changes on a number of hazardous
liquid and gas transmission lines. In response to this phenomenon, on
September 18, 2014, PHMSA issued an Advisory Bulletin \20\ notifying
operators of the potentially significant impacts such changes may have
on the integrity of a pipeline.
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\20\ PHMSA: ``Pipeline Safety: Guidance for Pipeline Flow
Reversals, Product Changes and Conversion to Service'' Advisory
Bulletin, 79 FR 56121, September 18, 2014; https://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Advisory%20Notices/ADB-2014-04_Flow_Reversal.pdf.
---------------------------------------------------------------------------

Data indicate that some pipelines also continue to be vulnerable to
issues stemming from outdated construction methods or materials. Much
of the older pipe in the Nation's pipeline infrastructure was made
before the 1970s using techniques that have proven to contain latent
defects due to the manufacturing process.\21\ Such defects cause the
pipe to be susceptible to developing hook cracks or other anomalies
that may, over time, lead to failures if they are not timely repaired.
For example, line pipe manufactured using low-frequency electric
resistance welding is susceptible to seam failure. A substantial amount
of this type of pipe is still in service; per PHMSA's ``Miles by Decade
of Installation Inventory Reports'' for hazardous liquid lines, there
were 92,271 miles of pre-1970s pipe still in service in 2017.\22\ The
IM regulations include specific requirements for evaluating such pipe
if located in HCAs, but infrequent-yet-severe failures that are
attributed to longitudinal seam defects continue to occur. Per PHMSA's
Accident and Incident database, between 2010 and 2017, 84 reportable
incidents were attributed to seam failures, resulting in over $220
million of property damage.^{23 24}
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\21\ See https://primis.phmsa.dot.gov/comm/FactSheets/FSPipeManufacturingProcess.htm for more information about pipe
manufacturing processes and known latent defects.
\22\ PHMSA's Annual Report Mileage for Hazardous Liquid or
Carbon Dioxide Systems; https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\23\ PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
\24\ The data can be narrowed down by selecting the
``hl2010toPresent'' Excel spreadsheet. Cell ``CR'' indicates the
identified location of the failure and whether the failure was in
the pipe body or in the pipe seam. If it was identified as a pipe
seam failure, Cells ``CW'' and ``CX'' provide additional information
on pipe seam type and pipe seam details, respectively.
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In the final rule, PHMSA strengthens the IM requirements to
identify and respond to the increased pipeline risks resulting from
operational changes, weather and associated geotechnical hazards, and
increased use and age of a pipe.
Enhanced Collection of Data
To keep the public safe and to protect the Nation's energy security
and reliability, operators and regulators must have an intimate
understanding of their entire pipeline system, including threats and
operations. However, with operators who are not required to report
certain information on certain currently unregulated pipelines, and
with aging pipelines that are not modernized for internal inspection,
there continue to be data gaps that make it hard to fully understand
the extent of the potential safety risks to the integrity of the
Nation's pipeline system.
PHMSA's regulations exempt rural gathering pipelines and gravity
pipelines. Gravity pipelines carry product by means of gravity, and
many gravity lines are short and within tank farms or other pipeline
facilities. However, some gravity lines are longer and can build up
high pressures. PHMSA is aware of gravity lines that traverse long
distances with significant elevation changes, which could have
significant consequences in the event of a release. Both gravity and
gathering lines are currently excluded from reporting requirements,
leaving large gaps in PHMSA's knowledge of these unregulated pipeline
systems. This is especially true because much of operators' and PHMSA's
data is obtained through testing and inspection under IM requirements,
which are not currently required for gathering and gravity lines.
To assess a pipeline's integrity, operators generally choose
between three methods of testing a pipeline: In-line inspection (ILI),
pressure testing, and direct assessment (DA). In 2017, PHMSA estimates
that slightly over 90 percent of the hazardous liquid line mileage in
HCAs is already piggable and almost 90 percent of these lines were
being inspected with ILI tools.
Operators perform ILIs by using special tools, sometimes referred
to as ``smart pigs,'' which are usually pushed through a pipeline by
the pressure and flow rate of the product being transported. As the
tool travels through the pipeline, it identifies and records potential
pipe defects or anomalies. Because these tests can be performed with
product in the pipeline, the pipeline does not have to be taken out of
service for testing to occur, which can reduce cost to the operator and
possible service disruptions to consumers. Further, ILI is a non-
destructive testing technique, and it can be less costly on a per-unit
basis to perform than other assessment methods. However, a very small
portion of hazardous liquid pipe segments cannot be inspected through
ILI because they are too short in length, which makes getting accurate
ILI tool results impractical due to tool speed variations. Other
hazardous liquid pipelines might not be inspected through ILI because
they do not have enough operating pressure or flow rate to run the
tool.
Pipeline operators typically use pressure tests to determine the
integrity (or strength) of the pipeline immediately after construction
and before placing the pipeline in service. In a pressure test, a test
medium (typically water) inside the pipeline is pressurized to a level
greater than the normal operating pressure of the pipeline. This test
pressure is held for a number of hours to ensure there are no leaks in
the pipeline.
Direct assessment is the evaluation of various locations on a
pipeline for corrosion threats. Operators will review operational
records and indirectly inspect the pipeline with coating surveys, such
as close interval, direct

[[Page 52266]]

current voltage gradient, and alternating current voltage gradient
surveys, to detect areas where the protective, anti-corrosion coating
applied to a pipeline may be faulty, as corrosion may be more likely in
these locations. Operators subsequently excavate and examine areas that
are likely to have suffered from corrosion. DA can be costly to use
without targeting specific locations. A limited number of specific
locations, however, may not give an accurate representation of the
condition of lengths of entire pipeline segments.
Ongoing research appears to indicate that ILI and hydrostatic
pressure ``spike'' testing are more effective than DA for identifying
pipe conditions related to cracking defects such as dents with stress
cracks, stress corrosion cracking (SCC), selective seam weld corrosion
(SSWC), and other seam-type cracking.\25\ Hydrostatic testing of
hazardous liquid pipelines requires testing to at least 125 percent of
the maximum operating pressure (MOP) for at least 4 continuous hours
and an additional 4 hours at a pressure of at least 110 percent of MOP
if the pipe is not visible. If there is concern about pipe cracks that
might grow due to pressure cycling, operating stress levels,
environmental conditions, and fatigue, then a spike test at a pressure
of up to or over 139 percent of MOP for a short period (up to a 30-
minute hold time or longer) may be conducted. A spike test detects pipe
body and seam cracks by causing any cracks that would later grow to
failure to fail during the hydrostatic test. Both regulators and
operators have expressed interest in improving ILI methods as an
alternative to hydrostatic testing for better risk evaluation and
management of pipeline safety. Hydrostatic pressure testing can result
in substantial costs and occasional disruptions in service, whereas ILI
testing can obtain data that is not otherwise obtainable via other
assessment methods, such as pipe wall loss, dents, and cracking.
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\25\ See: Comprehensive Study to Understand Longitudinal ERW
Seam Research & Development study task reports: Battelle Final
Reports (``Battelle's Experience with ERW and Flash Weld Seam
Failures: Causes and Implications''--Task 1.4), Report No. 13-002
(``Models for Predicting Failure Stress Levels for Defects Affecting
ERW and Flash-Welded Seams''--Subtask 2.4), Report No. 13-021
(``Predicting Times to Failure for ERW Seam Defects that Grow by
Pressure-Cycle-Induced Fatigue''--Subtask 2.5), and ``Final Summary
Report and Recommendations for the Comprehensive Study to Understand
Longitudinal ERW Seam Failures--Phase 1''--Task 4.5), which can be
found online at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
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In this final rule, PHMSA is addressing data gaps and increasing
the quality of data collected by expanding the reporting requirements
to cover both gathering and gravity lines and requiring that all lines
in HCAs be piggable for a better understanding of pipeline
characteristics. The final rule will also require operators to fully
integrate their pipeline data across all data sources to close any
remaining gaps.
Looking at Risk Beyond HCAs
In addition to improving IM programs for the pipe that they already
cover, PHMSA understands the importance of carefully reconsidering the
scope of the areas covered by IM requirements. While PHMSA's hazardous
liquid IM program manages risks primarily by focusing oversight on
areas with the greatest population density and environmental
sensitivity, it is imperative to protect the safety of environmental
resources and communities throughout the country. The changing
landscape of production, consumption, and product movement merits a
fresh look at the current scope of IM coverage.
The current definition of an HCA uses Census Bureau definitions of
urbanized areas or areas with a concentrated population.\26\ The HCA
definition also encompasses ``unusually sensitive areas,'' including
drinking water or ecological resource areas and commercially navigable
waterways. However, liquid spills, even outside HCAs, can result in
environmental damage necessitating clean up, restoration costs, and
lost use and non-use values. If operators do not periodically assess
and repair their pipelines, liquid spills are more likely to occur. In
fact, devastating incidents have occurred outside of HCAs in rural
areas where populations are sparse, and operators have not been
required to assess their lines as frequently as lines covered by IM.
Per PHMSA's databases, between 2010 and 2017, significant incidents at
hazardous liquid facilities accounted for over 993,097 barrels spilled,
24 injuries, and 10 fatalities. Out of those, over 702,091 barrels
spilled, 10 injuries, and four fatalities occurred in non-HCA
areas.\27\ These data show that ruptures with the potential to affect
populations, the environment, or commerce, can occur anywhere on the
Nation's pipeline system.
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\26\ Specifically, Sec. 195.450 states that a high population
area is an urban area, as defined and delineated by the Census
Bureau, that contains 50,000 or more people and has a population
density of at least 1,000 people per square mile, and an other
populated area is a place, as defined and delineated by the Census
Bureau, that contains a concentrated population, such as an
incorporated or unincorporated city, town, village, or other
designated residential or commercial area.
\27\ PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
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If constant improvement and zero incidents are goals for pipeline
operators,\28\ extending and prioritizing IM assessments and principles
to all parts of pipeline networks is an effective way to achieve those
goals. Extending IM assessments and principles to non-HCAs will help
clarify vulnerabilities and prioritize improvements, and this final
rule takes important steps towards developing that approach and will
lead operators to gather valuable information they may not have
collected if regulations were not in place.
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\28\ Major trade associations, including API and INGAA, have
publicly committed to a goal of zero incidents. See: https://www.api.org/oil-and-natural-gas/wells-to-consumer/transporting-oil-natural-gas/pipeline/pipeline-safety and https://www.ingaa.org/File.aspx?id=20463 for more details.
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In this final rule, PHMSA is requiring operators to assess onshore,
piggable pipelines outside of HCAs periodically using ILI or other
technology, if appropriate, to detect (and remediate) anomalies in all
locations within their pipeline systems. PHMSA is providing operators
with deadlines to verify their segment analyses to identify any new
HCAs and implement the appropriate actions. These changes would ensure
the remediation of anomalous conditions that could potentially impact
people, property, or the environment, while at the same time allowing
operators to allocate their resources based on pipeline risks and the
vulnerability of surrounding areas.
Recent Developments in Hazardous Liquid Pipeline Safety Regulation
On October 18, 2010, PHMSA posed a series of questions to the
public in the context of an ANPRM titled ``Pipeline Safety: Safety of
On-Shore Hazardous Liquid Pipelines'' (75 FR 63774). In that document,
PHMSA sought comments on several proposed changes to part 195,
including: (1) The scope of part 195 and existing regulatory
exceptions, (2) Criteria for designation of HCAs, (3) Leak detection
and emergency flow restricting devices, (4) Valve spacing, (5) Repair
criteria outside of HCAs, and (6) Stress corrosion cracking. The
questions in this ANPRM considered topics relating to the statutory
mandates; the post-Marshall, MI, NTSB and GAO recommendations; and
other pipeline safety mandates. Twenty-one organizations and
individuals submitted comments in response to the ANPRM.
PHMSA reviewed the received comments, the 2011 Pipeline Safety Act,

[[Page 52267]]

and the NTSB and GAO recommendations, and responded in the subsequent
NPRM published on October 13, 2015, (80 FR 61609). In summary, the NPRM
addressed the following areas: (1) Reporting requirements for gravity
lines, (2) Reporting requirements for gathering lines, (3) Inspections
of pipelines following extreme weather events and natural disasters,
(4) Periodic assessments of pipelines not subject to IM, (5) Repair
criteria, (6) Expanded use of leak detection systems, (7) Increased use
of in-line inspection tools, and (8) Clarifying other requirements. A
summary of comments and responses to those comments are provided later
in the document. The ANPRM and NPRM may be viewed at https://www.regulations.gov by searching for Docket No. PHMSA-2010-0229.

B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

After the issuance of the ANPRM on October 18, 2010, the 2011
Pipeline Safety Act included several statutory requirements related
directly to the topics being considered in the ANPRM. The related
topics and statutory citations that PHMSA considered within the context
of this rulemaking include, but are not limited to:
Section 5(f)--Requires, if appropriate, regulations issued
by the Secretary to expand integrity management system requirements, or
elements thereof, beyond high-consequence areas. These regulations are
to be dependent on an evaluation and report of whether integrity
management system requirements, or elements thereof, should be expanded
beyond high-consequence areas;
Section 8--Requires, if appropriate, regulations regarding
leak detection on hazardous liquid pipelines and establishing leak
detection standards. These regulations are to be dependent on a report
on the analysis of the technical limitations of current leak detection
systems, including the ability of the systems to detect ruptures and
small leaks that are ongoing or intermittent, and what can be done to
foster development of better technologies, and an analysis of the
practicability of establishing technically, operationally, and
economically feasible standards for the capability of such systems to
detect leaks, and the safety benefits and adverse consequences of
requiring operators to use leak detection systems;
Section 14--Permits PHMSA to issue regulations for
pipelines transporting non-petroleum fuels, such as biofuels;
Section 21--Requires a review on the regulation of Gas
(and Hazardous Liquid) Gathering Lines and the issuance of further
regulations, if appropriate; and
Section 29--Requires that operators consider seismicity
when evaluating pipeline threats.

C. National Transportation Safety Board Recommendation

On July 10, 2012, shortly after the 2011 Pipeline Safety Act was
passed, the NTSB issued its accident investigation report on the
Marshall, MI, accident. In it, the NTSB made additional recommendations
to update the hazardous liquid pipeline regulations. Pertaining
directly to this rule, the NTSB issued recommendation P-12-04, which
addressed the ``discovery of condition'' as follows:
NTSB Recommendation P-12-4: ``Revise Title 49 Code of
Federal Regulations 195.452(h)(2), the `discovery of condition,' to
require, in cases where a determination about pipeline threats has not
been obtained within 180 days following the date of inspection, that
pipeline operators notify the Pipeline and Hazardous Materials Safety
Administration and provide an expected date when adequate information
will become available.''

D. Summary of Each Topic

This final rule amends the Federal Pipeline Safety Regulations to
address the following topics. Details of the changes in this rule are
discussed in this document in Section IV, ``Analysis of Comments and
PHMSA Response,'' and Section V, ``Section-by-Section Analysis.''
(1) Extend Certain Reporting Requirements to Certain Gravity and Rural
Hazardous Liquid Gathering Lines
Gravity lines are pipelines that carry product by means of gravity
and are currently exempt from PHMSA regulations. Many gravity lines are
short and within tank farms or other pipeline facilities; however, some
gravity lines are longer and can build up large amounts of pressure.
Further, certain gravity lines may have significant elevation changes,
which can lead to serious consequences in the event of a release.
For PHMSA to effectively analyze the safety performance and risk of
gravity lines, PHMSA needs basic data about those pipelines. The agency
has the statutory authority to gather data for all gravity lines (49
U.S.C. 60117(b)). Accordingly, PHMSA is amending the Pipeline Safety
Regulations (PSR) to require that the operators of certain gravity
lines comply with requirements for submitting annual, safety-related
condition, and incident reports. PHMSA estimates that, at most, five
hazardous liquid pipeline operators will be affected. Based on comments
to the ANPRM from the American Petroleum Institute and the Association
of Oil Pipelines (API-AOPL), 3 operators have approximately 17 miles of
gravity-fed pipelines. PHMSA estimated that proportionally 5 operators
would have 28 miles of gravity-fed pipelines.
PHMSA is also amending the PSR to extend the annual, accident, and
safety-related condition reporting requirements of part 195 to all
hazardous liquid gathering lines. The Hazardous Liquid Pipeline Safety
Act of 1979 (Pub. L. 96-129) did not mandate the regulation of rural
gathering lines because at that time they were not thought to present a
significant enough risk to public safety to justify Federal regulation
based on the data available at that time. However, the Pipeline Safety
Act of 1992 (Pub. L. 102-508) authorized the issuance of safety
standards for regulated rural gathering lines based on a consideration
of certain factors and subject to certain exclusions. When PHMSA
adopted the current requirements for regulated rural gathering lines,
the agency made judgments in implementing those statutory provisions
based on the information available at that time.

[[Page 52268]]

Recent data indicates, however, that PHMSA regulates less than
4,000 miles of the approximately 30,000 to 40,000 miles of onshore
hazardous liquid gathering lines in the United States.\29\ That means
that about 90 percent of the onshore gathering line mileage is not
currently subject to any minimum Federal pipeline safety standards. The
NTSB has also raised concerns about the safety of hazardous liquid
gathering lines in the Gulf of Mexico and its inlets,\30\ which are
only subject to certain inspection and reburial requirements.
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\29\ PHMSA, ``Hazardous Liquid Pipeline Miles and Tanks,''
https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?Portalpages&NQUser=PDM_WEB_USER&NQPassword=Public_Web_User1&PortalPath=%2Fshared%2FPDM%20Public%20website%2F_portal%2FPublic%20Reports&Page=Infrastructure&Action=Navigate&col1=%22PHP%20-%20Geo%20Location%22.%22State%20Name%22&val1=%22%22, retrieved 11/
20/2018.
\30\ Deborah Hersman, Testimony before the Subcommittee on
Surface Transportation and Merchant Marine Infrastructure, Safety,
and Security Committee on Commerce, Science, and Transportation,
United States Senate Hearing on Ensuring the Safety of our Nation's
Pipelines, Washington DC, 6/24/2010. https://www.ntsb.gov/news/speeches/DHersman/Pages/Testimony_before_the_Subcommittee_on_Surface_Transportation_and_Merchant_Marine_Infrastructure_Safety_and_Security_Committ.aspx.
---------------------------------------------------------------------------

In the ANPRM, PHMSA asked whether the agency should repeal or
modify any of the exceptions for hazardous liquid gathering lines.
Section 195.1(a)(4)(ii) states that part 195 applies to a ``regulated
rural gathering line as provided in Sec. 195.11.'' PHMSA published a
final rule on June 3, 2008 (73 FR 31634), that prescribed certain
safety requirements for regulated rural gathering lines (i.e., the
filing of accident, safety-related condition, and annual reports;
establishing the MOP in accordance with Sec. 195.406; installing line
markers; and establishing programs for public awareness, damage
prevention, corrosion control, and operator qualification of
personnel).
The June 2008 final rule did not establish safety standards for all
rural hazardous liquid gathering lines. Some of those lines cannot be
regulated by statute (i.e., 49 U.S.C. 60101(b)(2)(B) states that ``the
definition of ``regulated gathering line'' for hazardous liquid may not
include a crude oil gathering line that has a nominal diameter of not
more than 6 inches, is operated at low pressure, and is in a rural area
that is not unusually sensitive to environmental damage''), and
Congress did not remove this exemption in the 2011 Pipeline Safety Act.
PHMSA is currently statutorily limited to regulating gathering
lines in HCAs and ``regulated rural gathering lines,'' which are
defined in Sec. 195.11 to mean onshore gathering lines in a rural area
that meet certain criteria (i.e., has a nominal diameter from 6\5/8\
in. (168 mm) to 8\5/8\ in. (219.1 mm), is in or within \1/4\ mile of an
unusually sensitive area as defined in Sec. 195.6, and operates at a
maximum pressure established under Sec. 195.406). This limitation
leaves gaps in the regulation of rural gathering lines not classified
as regulated rural gathering lines.
Further, PHMSA currently collects no data on unregulated gathering
lines. This lack of data prevents PHMSA from being able to determine
whether current regulations should be applied to currently unregulated
gathering lines. Therefore, in this final rule, PHMSA is requiring
reporting on all hazardous liquid gathering lines and will consider,
based on the nature of the data gathered, the appropriateness of
additional regulatory requirements, if any, for hazardous liquid
gathering lines in the future.
The final rule, however, does not address or require data
collection for transportation-related flow lines until further study
and cost analyses can be conducted. PHMSA notes that, per Section 12 of
the 2011 Pipeline Safety Act, Congress has provided PHMSA with the
authority to collect data on pipelines transporting oil off the grounds
of the well where it originated and across areas not owned by the
producer, regardless of the extent to which the oil has been processed,
if at all. Aside from this rulemaking, PHMSA may consider collecting
these data in the future. As discussed above, any decision PHMSA makes
to expand its oversight of gathering lines beyond what is currently
regulated will be driven by risk assessment and analysis based on
evaluations of incident and accident data, data related to
infrastructure, and further technological advancements such as the
unconventional production practices used in shale formations.

(2) Require Inspections of Pipelines in Areas Affected by Extreme
Weather and Natural Disasters

Extreme weather has been a contributing factor in several pipeline
failures. For example, in 1994, flooding in Texas led to river scour
and ground movement that caused the failure of eight pipelines and the
release of more than 35,000 barrels of hazardous liquids into the San
Jacinto River. Some of that released product also ignited, causing
minor burns and other injuries to nearly 550 people according to the
NTSB. In July 2011, a pipeline failure associated with river bottom
scour occurred near Laurel, MT, causing the release of an estimated
1,000 barrels of crude oil into the Yellowstone River. That area had
experienced extensive flooding due to warm weather causing the rapid
melting of large snowpack levels in the weeks leading up to the
failure. The operator estimated the cleanup costs at approximately $135
million. In January 2015, another pipeline failure caused by river
bottom scour again occurred on the Yellowstone River, spilling
approximately 758 barrels of crude oil into the river, causing the
shutdown of nearby drinking-water intakes.\31\ Additionally, on October
21, 2016, extreme localized flooding, soil erosion, and ground movement
caused a release of over 1,238 barrels of gasoline into the Loyalsock
Creek in Lycoming County, PA. Further, on March 20, 2018, heavy rain
caused a pipeline to rupture and release 1,400 barrels of diesel fuel
into Big Creek at Solitude, IN. Specifically, a girth weld on the
pipeline ruptured due to land slippage caused by the saturated soil.
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\31\ https://deq.mt.gov/Portals/112/DEQAdmin/DIR/Documents/Bridger%20Consent%20Order/Final%20Bridger%20Consent%20Order.pdf?ver=2017-02-09-121902-843.
---------------------------------------------------------------------------

Weather events and natural disasters that can cause river scour,
soil subsidence or ground movement may subject pipelines to additional
external loads, which could cause a pipeline to fail. These conditions
can pose a threat to the integrity of pipeline facilities if those
threats are not promptly identified and mitigated. While the existing
regulations provide for design standards that consider the load that
may be imposed by geological forces, events like the ones described
above can quickly impact the safe operation of a pipeline and have
severe consequences if not mitigated and remediated as quickly as
possible.
PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to
communicate the potential for damage to pipeline facilities caused by
severe flooding, including actions that operators should consider
taking to ensure the integrity of pipelines in the event of flooding,
river scour, river channel migration, and earth movement.\32\ As PHMSA
has noted in a series of Advisory Bulletins, hurricanes are also
capable of causing extensive damage to both offshore and inland
pipelines (e.g., Hurricane Ivan, September 23, 2004 (69 FR 57135);
Hurricane Katrina, September 7, 2005

[[Page 52269]]

(70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)).
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\32\ ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' April 9, 2015, 80 FR 19114; and January 19, 2016, 81 FR
2943. See also ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
May 2, 2019, 84 FR 18919.
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These events demonstrate the importance of working to ensure that
our Nation's waterways and the public are adequately protected from
pipeline risks in the event of a natural disaster or extreme weather.
PHMSA is aware that many operators perform inspections following such
events; however, because it is not a requirement, some operators do
not. Therefore, PHMSA is amending the PSR to require that operators
commence inspection of their potentially affected assets within 72
hours after the cessation of an extreme weather event such as a
hurricane, flood, landslide, earthquake, or other natural disaster that
has the likelihood to damage infrastructure. PHMSA would not expect
operators to comply with these provisions for weather events when,
considering the physical characteristics, operating conditions,
location, and prior history of the affected system, the event would not
have a likelihood of damage to the pipeline. For example, extreme
weather events would not include rain events that do not exceed the
high-water banks of the rivers, streams or beaches in proximity to the
pipeline; rain events that do not result in a landslide in the area of
the pipeline; storms that do not produce winds at tropical storm or
hurricane level velocities; or earthquakes that do not cause soil
movement in the area of the pipeline.
Under this requirement, an operator must inspect all potentially
affected pipeline facilities following these types of events to detect
conditions that could adversely affect the safe operation of the
pipeline. The operator must consider the nature of the event and the
physical characteristics, operating conditions, location, and prior
history of the affected pipeline in determining whether the event
necessitates an inspection as well as the appropriate method for
performing the inspection. If the event creates a likelihood that there
is damage to pipeline infrastructure, the operator must commence an
inspection within 72 hours after the cessation of the event, defined as
the point in time when the area can be safely accessed by personnel and
equipment, including availability of personnel and equipment, required
to perform the inspection. PHMSA has found that 72 hours is reasonable
and achievable in most cases based on prior observations of extreme
events. If an operator finds an adverse condition, the operator must
take appropriate remedial action to ensure the safe operation of a
pipeline based on the information obtained from the inspection. Such
actions might include, but are not limited to:
Reducing the operating pressure or shutting down the
pipeline;
Isolating pipelines in affected areas and performing
``stand up'' leak tests;
Modifying, repairing, or replacing any damaged pipeline
facilities;
Preventing, mitigating, or eliminating any unsafe
conditions in the pipeline rights-of-way;
Performing additional patrols, depth of cover surveys, ILI
or hydrostatic tests, or other inspections to confirm the condition of
the pipeline and identify any imminent threats to the pipeline;
Implementing emergency response activities with Federal,
State, or local personnel; and
Notifying affected communities of the steps that can be
taken to ensure public safety.
This requirement is based on the experience of PHMSA and is
expected to increase the likelihood that operators will find and
respond to safety conditions more quickly.
(3) Require Assessments of Pipelines That Are Not Already Covered Under
the IM Program Requirements at Least Once Every 10 Years
PHMSA is requiring that operators periodically assess onshore,
piggable, hazardous liquid pipeline segments in non-HCAs. PHMSA has
determined that expanding assessment requirements to these non-HCA
pipeline segments will provide operators with valuable information they
may not have collected if regulations were not in place. Such a
requirement works to ensure prompt detection and remediation of
corrosion and other deformation anomalies across the Nation, not just
in populated or environmentally sensitive areas as defined by Federal
regulations. There is still considerable consequence risk--regarding
personal safety, environmental damage, and economic impact--of a spill
in less-populated areas, into waterways not designated as
``commercially navigable,'' recreational areas, commercial fishing
areas, and agriculturally productive areas that do not meet the
definition of an HCA.
In this rulemaking, Sec. 195.416 requires operators to assess
onshore, piggable, non-HCA, hazardous liquid pipeline segments at least
once every 10 years, which allows operators to prioritize assessments
in HCAs over assessments in non-HCAs (the assessment period is 5 years
for hazardous liquid pipeline segments that are in or can otherwise
affect an HCA). The individuals who review the results of these
assessments will need to be qualified by knowledge, training, and
experience and will be required to consider any uncertainty in the
results obtained, including ILI tool tolerance, when determining
whether any conditions could adversely affect the safe operation of a
pipeline. Such determinations will have to be made promptly, but no
later than 180 days after an inspection, unless the operator
demonstrates that the 180-day deadline is impracticable.
Operators are required to comply with the other provisions in part
195 in implementing the requirements in Sec. 195.416. That includes
having appropriate provisions for performing these periodic assessments
and any resulting repairs in an operator's procedural manual (see Sec.
195.402); adhering to the recordkeeping provisions for inspections,
tests, and repairs (see Sec. 195.404); and taking appropriate remedial
action under Sec. 195.401(b)(1), as discussed below.
Such requirements will help ensure operators obtain information
necessary for the detection and remediation of corrosion and other
deformation anomalies in all locations, not just HCAs. Of the many
assessment methods, PHMSA has found that ILI in many cases is the most
efficient and effective. Operators can perform ILIs while pipelines are
in service without any interruption of product flow. Further, ILIs are
non-destructive and can provide information beyond direct assessments,
which can only tell whether there is exterior coating damage or
corrosion, and hydrotests, which are essentially ``pass'' or ``fail.''
ILI tools, which are constantly improving, can provide accurate
information on internal corrosion, external corrosion, cracks, and
gouges. Additionally, there is robust guidance and documentation for
the use of ILI; API and the National Association of Corrosion Engineers
(NACE) have developed standards for ILIs that provide guidelines on
appropriate tool selection, assessment procedures, and the
qualification of personnel conducting assessments.
Currently, operators said they are performing ILI assessments on a
large portion of both HCA and non-HCA pipeline mileage, even though no
regulation requires them to assess mileage outside of HCAs. Reported
repairs in non-HCA segments reflect this indication. PHMSA wants to
best ensure that current assessment rates continue and expand to those
areas not voluntarily assessed. PHMSA has determined that by adopting
these amendments to the existing pipeline safety regulations, data
collection will continue to improve across the entire pipeline system,
and anomalies that

[[Page 52270]]

may have previously gone undetected in non-HCAs will be detected and
repaired in a more consistent manner.
(4) Expand the Use of Leak Detection Systems for Certain Hazardous
Liquid Pipelines
With respect to new hazardous liquid pipelines, PHMSA is amending
Sec. 195.134 to require that all new covered pipelines, in both HCAs
and non-HCAs, have leak detection systems within 1 year after this
final rule is published in the Federal Register, and all covered
pipelines constructed prior to the rule's publication have leak
detection systems within 5 years after this rule is published. Recent
pipeline accidents, including related failures that occurred in 2010 on
a crude oil pipeline in Salt Lake City, UT; a failure of another crude
oil pipeline in Santa Barbara, CA, in 2015; a crude oil release in
Belfield, ND, in 2016; and the failure of refined products lines in
Dono Ana County, NM, in 2018, corroborate the significance of having an
adequate means for identifying leaks in all locations along the
pipeline right-of-way. PHMSA, aware of the significance of leak
detection, held a 2-day workshop in Rockville, MD, on March 27-28 of
2012.\33\ These workshops sought comment from the public concerning
many of the issues raised in the 2010 ANPRM, including leak detection
expansion. Both workshops were well attended, and PHMSA received
valuable input from stakeholders on the technical gaps and challenges
for future research and ways to leverage resources to achieve common
objectives and reduce duplication of research programs. Participants
also discussed the development of leak detection for all pipeline types
and the capabilities and limitations of current leak detection
technologies.
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\33\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=75.
---------------------------------------------------------------------------

With respect to existing pipelines, part 195 currently contains
mandatory leak detection requirements for only those hazardous liquid
pipelines that could affect an HCA. Congress included additional
requirements for leak detection systems in section 8 of the 2011
Pipeline Safety Act. That legislation requires the Secretary to submit
a report to Congress, within 1 year of the enactment date, on the use
of leak detection systems, including an analysis of the technical
limitations and the practicability, safety benefits, and adverse
consequences of establishing additional standards for the use of those
systems. Congress authorized the issuance of regulations for leak
detection if warranted by the findings of the report.
PHMSA publicly provided the results of the 2012 Kiefner and
Associates study on leak detection systems in the pipeline industry,
including the current state of technology. The study found that most
leak detection technologies can be retrofitted to existing pipelines,
though many operators ``fear investing in leak detection systems, with
potentially little benefit to show from them and no way to truly
measure success in a standardized way,'' resulting in leak detection
being implemented ``cautiously, and incrementally, on measurement and
other systems that are already in place.'' \34\
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\34\ Kiefner and Associates, Inc., ``Final Report on Leak
Detection Study-DTPH56-11-D-000001,'' December 10, 2012; https://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Press%20Release%20Files/Leak%20Detection%20Study.pdf.
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Based on information available to PHMSA, including post-accident
reviews and the Kiefner Report, the need to expand the use of leak
detection systems and strengthen the current leak detection
requirements is clear. A robust leak detection system is extremely
important to hazardous liquid operators because it triggers all other
impact mitigation measures that an operator should plan for, including
safe flow shutdown, spill containment, cleanup, and remediation. In
this final rule, PHMSA is modifying Sec. 195.444 to require a means
for detecting leaks on all portions of a hazardous liquid pipeline
system, including non-HCA lines, and to require that operators perform
an evaluation to determine what kinds of systems must be installed to
adequately protect the public, property, and the environment. The
factors that must be considered during that evaluation include (but are
not limited to) the characteristics and history of the affected
pipeline, the capabilities of available leak detection systems, and the
location of emergency response personnel. PHMSA is retaining the
requirements in Sec. Sec. 195.134 and 195.444 that each new
computational leak detection system comply with the applicable
requirements in API Recommended Practice 1130.\35\
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\35\ API RP 1130 focuses on the design, implementation, testing
and operation of Computational Pipeline Monitoring (CPM) systems
that use an algorithmic approach to detect hydraulic anomalies in
pipeline operating parameters for hazardous liquid pipelines.
---------------------------------------------------------------------------

Given the difficulties identified in the Kiefner study related to
leak detection performance standards, PHMSA is not making any
additional changes to the regulations concerning specific leak
detection system performance criteria requirements at this time. PHMSA
will be studying this issue further and may make proposals concerning
this topic in a later rulemaking.
(5) Increase Accommodation of In-Line Inspection Tools
In this final rule, PHMSA is amending the part 195 regulations to
require that all hazardous liquid pipelines in HCAs and areas that
could affect an HCA be made capable of accommodating ILI tools within
20 years, unless subject to PHMSA approval, the basic construction of a
pipeline will not accommodate the passage of such a device or the
operator determines it would abandon the pipeline because of the cost
of complying with the amendment. Per the petition process at Sec.
190.9, operators would be required to document these determinations and
submit the documentation to PHMSA for approval.
Modern ILI tools can provide a relatively complete examination of
the entire length of a pipeline, including information about threats
that other assessment methods cannot always identify. ILI tools also
provide superior information about incipient flaws (i.e., flaws that
are not yet a threat to pipeline integrity, but that could become so in
the future), thereby allowing these conditions to be monitored over
consecutive inspections and remediated before a pipeline failure
occurs. Hydrostatic pressure testing, another well-recognized method,
reveals flaws (such as wall loss and cracking flaws) that cause pipe
failures at pressures that exceed actual operating conditions, but only
allows operators to determine whether a required safety margin is met
(i.e., pass/fail) and does not provide information about the existence
of anomalies that could deteriorate over time between tests. Similarly,
external corrosion direct assessment (ECDA) is a form of direct
assessment that can identify instances where coating damage or
ineffective coatings may be affecting pipeline integrity, but operators
must perform additional activities, including follow-up excavations and
direct examinations, to verify the extent of that threat. ECDA also
does not provide information about the internal condition of a pipe to
the extent an ILI tool would.
The current regulations for the passage of ILI devices in hazardous
liquid pipelines are prescribed in Sec. 195.120, which require that
new and replaced pipelines are designed to accommodate ILI tools. The
basis for these requirements is a 1988 law that addressed the
Secretary's authority with regard to requiring the accommodation

[[Page 52271]]

of ILI tools. This law required the Secretary to establish minimum
Federal safety standards for the use of ILI tools, but only in newly
constructed and replaced hazardous liquid pipelines (Pub. L. 100-561).
As the Research and Special Programs Administration (RSPA; a
predecessor agency of PHMSA), explained in the final rule published on
April 12, 1994 (59 FR 17275), that promulgated Sec. 195.120, ``the
clear intent of th[at] congressional mandate [wa]s to improve an
existing pipeline's piggability,'' and to ``require the gradual
elimination of restrictions in existing hazardous liquid and carbon
dioxide lines in a manner that will eventually make the lines
piggable.'' RSPA also noted that Congress amended the 1988 law in the
Pipeline Safety Act of 1992 (Pub. L. 102-508) to require the periodic
internal inspection of hazardous liquid pipelines, including with ILI
tools in appropriate circumstances. In 1996, Congress passed another
law further expanding the Secretary's authority to require pipeline
operators to have systems that can accommodate ILI tools. In
particular, Congress provided additional authority for the Secretary to
require the modification of existing pipelines whose basic construction
would accommodate an ILI tool to accommodate such a tool and permit
internal inspection (Pub. L. 104-304). RSPA established requirements
for the use of ILI tools in pipelines that could affect HCAs in a final
rule published on December 1, 2000 (65 FR 75378).
Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the
requirements for the passage of ILI tools to be extended to existing
hazardous liquid pipeline facilities, provided the basic construction
of those facilities can be modified to permit the use of smart pigs.
The current requirements apply only to new hazardous liquid pipelines
and to line sections where the line pipe, valves, fittings, or other
components are replaced. Exceptions are also provided for certain kinds
of pipeline facilities, including manifolds, piping at stations and
storage facilities, piping of a size that cannot be inspected with a
commercially available ILI tool, and smaller-diameter offshore
pipelines.
In this final rule, PHMSA is taking steps to further facilitate the
gradual elimination of pipelines that are not capable of accommodating
smart pigs in accordance with the authority provided in section
60102(f)(1)(B). PHMSA is limiting the circumstances where a pipeline
can be constructed without being able to accommodate a smart pig. Under
the current regulation, an operator can petition the PHMSA
Administrator for such an allowance for reasons of impracticability,
emergencies, construction time constraints, costs, and other unforeseen
construction problems. PHMSA believes that an exception should still be
available for emergencies and where the basic existing construction of
a pipeline makes that accommodation impracticable.
Regulations already require that new and replaced pipelines
accommodate ILI tools, and many of the pipelines covered by this new
rule will need to be replaced and therefore will accommodate ILI tools
before the end of the 20-year implementation period. Providing industry
with sufficient time to implement this provision allows the industry to
prioritize retrofits and replacements based on age or other factors; it
also reduces the mileage of pipeline potentially needing to be replaced
before it has reached the limit of its operational life. PHMSA
determined that the 20-year timeline strikes the appropriate balance
between the need for upgrades with the operational challenges of making
these changes.
(6) Clarify Other Requirements
In this final rule, PHMSA is also making several other clarifying
changes to the regulations that are intended to improve compliance and
enforcement. First, PHMSA is proposing to revise paragraph (b)(1) of
Sec. 195.452 to better harmonize this section with other parts of the
current regulations. Currently, Sec. 195.452(b)(2) requires that
segments of new pipelines that could affect HCAs be identified before
the pipeline begins operations, and Sec. 195.452(d)(1) requires that
baseline assessments for covered segments of new pipelines be completed
by the date the pipeline begins operation. However, Sec. 195.452(b)(1)
does not require an operator to draft its IM program for a new pipeline
until 1 year after the pipeline begins operation. These provisions are
inconsistent, as the identification of could-affect segments and
performance of baseline assessments are elements of the written IM
program. PHMSA is amending the table in (b)(1) to resolve this issue by
eliminating the 1-year compliance deadline for Category 3 pipelines. An
operator of a new pipeline is required to develop its written IM
program before the pipeline begins operation--there is no burden
associated with this amendment because operators already were required
to report to DOT prior to construction.
Second, as mentioned in the non-HCA assessment section, operators
of both HCA lines and non-HCA lines will have equal requirements for
the ``discovery'' of conditions, which occurs when an operator has
adequate information about a condition to determine that it presents a
potential threat to the integrity of the pipeline. An operator must
promptly, but no later than 180 days after an integrity assessment,
obtain sufficient information about a condition to make that
determination, unless the operator can demonstrate that the 180-day
period is impracticable. This could include demonstrating why such
information would not be available prior to that date. If an operator
believes that unique circumstances exist in a particular case that make
the 180-day period impracticable, the operator must submit a
notification to PHMSA and provide an expected date when adequate
information will become available. The submission of such a
notification, by itself, will not affect compliance determinations on
whether the 180-day requirement was met. PHMSA is thereby amending the
existing ``discovery of condition'' language at Sec. 195.452(h)(2) in
the pipeline safety regulations to reflect these changes.
A decade's worth of IM inspection experience has shown that many
operators are performing inadequate information analyses (i.e., they
are collecting information but are not affording it sufficient
consideration, or they are not promptly evaluating the information they
have gathered following events that have increased risk, such as
historic weather events). Ongoing data integration is one of the most
important aspects of the IM program, and operators must account for
interactions between threats or conditions affecting the pipeline when
setting priorities for dealing with identified issues. For example,
evidence of potential corrosion in an area with foreign pipeline
crossings,\36\ nearby current interference from power lines and
electrically powered transport systems, evidence of land movement or
waterway channel changes that may impact pipeline integrity, and recent
aerial patrol indications of excavation activity could indicate a
priority for operators to reassess risk and make timely changes to
their IM program to reduce that risk. Consideration of each of these
factors individually would not necessarily reveal any need for priority
attention. PHMSA is concerned that a major benefit to pipeline safety
intended in the IM rule is not being realized

[[Page 52272]]

because of inadequate information analyses.
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\36\ Foreign pipelines can include other hazardous liquid,
natural gas, water, sewer, or drainage pipelines.
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For this reason, PHMSA is adding specificity to paragraph (g) by
establishing several pipeline attributes that must be included in these
analyses and requiring explicitly that operators integrate analyzed
information. PHMSA is also requiring operators to consider explicitly
any spatial relationships among anomalous information. PHMSA supports
the use of computer-based geographic information systems (GIS) to
record this information. GIS systems can be beneficial in identifying
spatial relationships, but analysis is required to identify where these
relationships could result in situations adverse to pipeline integrity.
Second, PHMSA is requiring operators to verify their pipeline
segment identification (as HCAs or otherwise) annually by determining
whether factors considered in their analysis have changed. Section
195.452(b) currently requires that operators identify each segment of
their pipeline that could affect an HCA in the event of a release, but
there is no explicit requirement that operators assure that their
identification of covered segments remains current. As time goes by,
the likelihood increases that factors considered in the original
identification of covered segments may have changed. Construction
activities or erosion near the pipeline could change local topography
in a way that could cause product released in an accident to travel
farther than initially analyzed. Changes in agricultural land use could
also affect an operator's analysis of the distance released product
could be expected to travel. Changes in the deployment of emergency
response personnel could increase the time required to respond to a
release and result in a release affecting a larger area if the original
segment identification relied on emergency response in limiting the
transport of released product. Therefore, PHMSA has determined that
operators should periodically re-visit their initial analyses to
determine whether they need updating; operators might identify new HCAs
in subsequent analyses.
The change that PHMSA is adopting does not automatically require
operators to re-perform their segment analyses. Rather, it requires
operators to first identify the factors considered in their original
analyses, determine whether those factors have changed, and consider
whether any such change would likely affect the results of the original
segment identification. If so, the operator is required to perform a
new segment analysis to validate or change the endpoints of the
segments affected by the change.
Further, Section 29 of the 2011 Pipeline Safety Act states that
``[i]n identifying and evaluating all potential threats to each
pipeline segment pursuant to parts 192 and 195 of title 49, Code of
Federal Regulations, an operator of a pipeline facility shall consider
the seismicity of the area.'' While seismicity is already mentioned at
several points in the IM program guidance provided in Appendix C of 49
CFR part 195, PHMSA is amending the PSR to further comply with
Congress's directive by including an explicit reference to seismicity
in the list of risk factors that must be considered in establishing
assessment schedules (Sec. 195.452(e)), performing information
analyses (Sec. 195.452(g)), and implementing preventive and mitigative
measures (Sec. 195.452(i)) under the IM requirements.
Finally, the PIPES Act of 2016 contained two sections PHMSA
identified as self-executing and that PHMSA could incorporate into the
PSR without notice of public comment or previous proposed rulemaking.
Section 14 of the PIPES Act of 2016 requires operators of hazardous
liquid pipeline facilities to provide safety data sheets to the
designated Federal On-Scene Coordinator and appropriate State and local
emergency responders within 6 hours of a telephonic or electronic
notice of the accident to the National Response Center. Section 25 of
the PIPES Act of 2016 requires operators of underwater hazardous liquid
pipeline facilities in HCAs that are not offshore pipeline facilities
and that any portion of which are located at depths greater than 150
feet below the surface of the water to complete ILI assessments
appropriate to the integrity threats specific to those pipelines no
less frequently than once every 12 months. Furthermore, section 25 of
the PIPES Act of 2016 requires that operators use pipeline route
surveys, depth of cover surveys, pressure tests, ECDAs, or other
technology that the operator demonstrates can further the understanding
of the condition of the pipeline facility, as necessary to assess the
integrity of those pipelines on a schedule based on the risk that the
pipeline facility poses to the HCA in which the facility is located.
PHMSA is amending the PSR by codifying the statutory language of these
provisions.

III. Liquid Pipeline Advisory Committee Recommendations

The Liquid Pipeline Advisory Committee (LPAC) is a statutorily
mandated advisory committee that advises PHMSA on proposed safety
standards, risk assessments, and safety policies for hazardous liquid
pipelines. The Pipeline Advisory Committees (PAC) were established
under the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App.
1-16) and the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601).
Each committee consists of 15 members, with membership divided among
the Federal and State agencies, the regulated industry, and the
public.\37\ The PACs advise PHMSA on the technical feasibility,
practicability, and cost-effectiveness of each proposed pipeline safety
standard.
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\37\ Members from the general public include two members who
have education, background, or experience in environmental
protection or public safety. At least one of the five members must
have education, background, or experience in risk assessment and
cost-benefit analysis. No public member can have a significant
interest in the pipeline, petroleum, or gas industry. At least one
of the public members must have no financial interests in the
pipeline, petroleum, or natural gas industries. See section 12(d),
``Liquid Pipeline Advisory Committee Charter--October 2018 to
October 2020,'' https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/standards-rulemaking/pipeline/4396/lpac-charter-final-102418.pdf.
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On February 1, 2016, the LPAC met at the Hilton Arlington in
Arlington, VA, to discuss this rulemaking. During the meeting, the LPAC
considered the specific regulatory proposals of the NPRM and discussed
various comments to the NPRM proposed by the pipeline industry, public
interest groups, and government entities. To assist the LPAC in their
deliberations, PHMSA presented a description and summary of the eight
major issues in the NPRM and the comments received on those issues, as
well as some sample regulatory text changes to foster discussion.
During the meeting, eight votes were taken: One vote on each major
topic of the NPRM. For each major topic of the rule, the LPAC came to a
consensus decision that the provisions of the rulemaking would be
technically feasible, reasonable, cost-effective, and practicable,
provided PHMSA made certain changes. The order the topics were
discussed in, the changes the committee agreed upon, and the
corresponding vote counts were as follows:
Gravity lines: In the NPRM, PHMSA proposed to subject gravity lines
to reporting requirements for data gathering purposes, as there are
currently no regulatory requirements for these lines and little data
for potential regulatory decision-making purposes. The LPAC voted 9-1
that the NPRM, with respect to gravity lines, as published in the
Federal Register, and the draft regulatory evaluation were technically
feasible, reasonable, cost-

[[Page 52273]]

effective, and practicable, if PHMSA made the following changes: Modify
(shorten) the reporting form, require no National Pipeline Mapping
System (NPMS) submissions, provide reporting exceptions for lower-risk
pipelines (for example, intra-plant lines), allow a 1-year
implementation period for annual reporting, and allow a 6-month
implementation period for accident reporting.
The LPAC agreed that PHMSA should modify the reporting forms to
gather only the data necessary for PHMSA to determine whether these
lines need to be regulated in the future. LPAC members representing the
pipeline industry requested that PHMSA consider reporting exceptions
for lower-risk pipelines, such as intra-plant gravity lines. The same
members also requested that any reporting requirements for gravity
lines not include NPMS submissions, asserting that incorporating that
data into a mapping system would be costly compared to the amount of
risk these lines pose. LPAC members representing the public did not
support these recommendations. They noted that as gravity line mileage
is already limited, and the reporting requirement is only being used to
gather data, excepting a subset of this limited mileage from reporting
requirements would be counter-productive. Further, the public members
strongly suggested that NPMS submissions be included for gravity lines,
as location could be an important data point PHMSA could collect.
Gathering lines: In the NPRM, PHMSA proposed to collect information
on all gathering lines and subject regulated gathering lines to
periodic assessment and leak detection requirements. Much of the LPAC's
discussion for gathering lines mirrored the topics discussed regarding
gravity lines. During the discussion, PHMSA noted that under 49 U.S.C.
60132, only transmission-pipeline operators are required to submit
mapping data for use in the NPMS. As a result, the LPAC removed
language concerning NPMS submissions by gathering line operators.
Ultimately, the committee voted 10-0 that the NPRM regarding gathering
lines, as published in the Federal Register, and the draft regulatory
evaluation are technically feasible, reasonable, cost effective, and
practicable if PHMSA made the following changes: modify (shorten) the
reporting form, allow a 1-year implementation period for annual
reporting, and allow a 6-month implementation period for accident
reporting.
Leak detection: In the NPRM, PHMSA proposed that all hazardous
liquid pipelines transporting liquid in single phase (without gas in
the liquid) include a leak detection system and have it operate and
maintained per specified standards. Many commenters noted that there
was no implementation period for PHMSA's proposed leak detection
requirements. The LPAC proposed a 5-year implementation period for leak
detection systems on existing lines and a 1-year implementation period
for leak detection systems on new lines. The LPAC also recommended
PHMSA not apply leak detection requirements to offshore gathering lines
due to various technical challenges associated with flow monitoring and
leak detecting. The LPAC voted unanimously that the NPRM, regarding
leak detection, as published in the Federal Register, and the draft
regulatory evaluation are technically feasible, reasonable, cost
effective, and practicable if PHMSA made the following changes: Allow a
5-year implementation period for existing pipelines, allow a 1-year
implementation period for new pipelines, and exempt offshore gathering
lines from the leak detection requirements.
Clarifying other requirements: In the NPRM, PHMSA proposed to
revise the IM requirements to specify additional pipeline attributes
for operators to analyze when evaluating the integrity of pipelines in
HCAs; to require the integration of all sources of information,
including spatial relationships, when determining pipeline integrity;
to require operators have a written IM plan prior to a specific
pipeline's operation; and to require annual HCA segment identification
and verification. During the meeting, the LPAC primarily discussed
whether there should be a timeframe for implementing the specific data
attributes and integrating all sources of information when determining
pipeline integrity. Committee members representing the public argued
that, because these provisions were clarifications of existing
requirements, operators should have already been performing many of
these actions, and an extended implementation period would not make
sense. Several members who represented the public pushed for a 1-year
implementation period. LPAC members representing the industry noted
that developing data integration systems to a level that PHMSA would
like could be expensive and time-consuming, possibly taking several
years. Further, LPAC members representing industry noted that while a
lot of data integration is already occurring in operators' IM programs,
it could take some operators an extended period to adjust their
software to incorporate all the items in PHMSA's proposed list. LPAC
members representing industry proposed PHMSA allow operators a 3-year
deadline from the rule's issuance to fully implement the proposed list
of attributes. Ultimately, the LPAC voted 7-3 that the NPRM, regarding
the data integration requirements, as published in the Federal
Register, and the draft regulatory evaluation are technically feasible,
reasonable, cost-effective, and practicable if operators begin
implementing the requirements upon the rule's issuance with a deadline
of 3 years for full implementation.
Inspections following extreme weather events: In the NPRM, PHMSA
proposed requiring operators to perform inspections of pipelines that
may have been affected by natural disasters or extreme weather events
within 72 hours after the cessation of the event to better ensure that
no conditions exist that could adversely affect the safe operation of
that pipeline. The LPAC voted unanimously that the NPRM, as it relates
to inspections following extreme weather events, as published in the
Federal Register, and the draft regulatory evaluation are technically
feasible, reasonable, cost-effective, and practicable, if PHMSA
included the term ``landslide'' as a specific extreme weather event and
qualify the term ``other similar events'' as it pertains to triggering
the requirements of performing an inspection by tying the term to those
events ``that the operator determines to have a significant likelihood
of damage to infrastructure.'' Further, the LPAC recommended PHMSA
clarify that the purpose of the inspection is to ``detect conditions
that could adversely affect the safe operation of the pipeline'' and
not ``ensure that no conditions exist that could adversely affect the
safe operation of the pipeline.'' The LPAC also recommended PHMSA
clarify that the inspection per these requirements would be an initial
inspection, conducted within 72 hours of the area being safely
accessible by personnel and equipment, to determine if any damage has
occurred and whether additional assessments are necessary.
Periodic assessments in non-HCAs: In the NPRM, PHMSA proposed to
require operators to assess non-HCA pipelines at least once every 10
years using ILI or other equivalent methods. The LPAC agreed on this
requirement and wanted to ensure it was not more restrictive than the
requirement for assessing lines

[[Page 52274]]

in HCAs. The LPAC voted unanimously that, regarding the provisions of
the NPRM related to periodic assessments, the NPRM, as published in the
Federal Register, and the draft regulatory evaluation are technically
feasible, reasonable, cost-effective, and practicable if PHMSA ensured
that the periodic assessment requirement applies to regulated pipelines
that are not currently subject to the IM requirements at Sec. 195.452,
and made the methods operators use to assess non-HCA pipelines
consistent with the methods operators use to assess HCA pipelines and
allow operators to choose the appropriate tool for the appropriate
threat.
Making all pipelines in HCAs able to accommodate ILI tools: In the
NPRM, PHMSA proposed to require all pipelines in HCAs be capable of
accommodating ILI tools within 20 years. The LPAC voted 9-1 that,
regarding the provision of the rule requiring the use of ILI tools in
all HCAs, the NPRM, as published in the Federal Register, and the draft
regulatory evaluation are technically feasible, reasonable, cost-
effective, and practicable provided PHMSA insert a phrase stating that
an operator can also file a petition if it determines it would abandon
or otherwise shut down a pipeline because of the compliance cost of the
provision.
Repair criteria: In the NPRM, PHMSA proposed to make various
changes to the existing repair criteria to reflect an improved
prioritization of repairing abnormal pipeline conditions. The LPAC
voted unanimously that, with regard to repair criteria for both HCA and
non-HCA pipeline segments, the NPRM, as published in the Federal
Register, and the draft regulatory evaluation are technically feasible,
reasonable, cost-effective, and practicable if PHMSA considers allowing
recognized engineering analyses to determine whether applicable dents
and cracks are non-injurious and need no further investigation, and
gives ``full and equal consideration to the industry comments that were
discussed [at the meeting].'' \38\ Those hazardous liquid industry
comments provided at the LPAC meeting for PHMSA to consider were as
follows:
---------------------------------------------------------------------------

\38\ At the Advisory Committee meeting, member Craig Pierson,
representing the pipeline industry, submitted for the members'
consideration a written recommendation regarding repair criteria
anomalies.
---------------------------------------------------------------------------

Repair Criteria for both HCA and non-HCA pipeline segments:
1. Regarding ``Immediate'' conditions:
a. Include crack anomalies greater than 70 percent of wall
thickness or the tool's maximum measurable depth if it is less than 70
percent;
b. Remove specific references to ``any indication'' of significant
stress corrosion cracking (SCC) and selective seam weld corrosion
(SSWC).
c. Allow for an industry recognized engineering analysis to
determine those dents that are non-injurious and require no further
investigation; and
d. 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 MOP at the location
of the anomaly, which should also include injurious cracks and SSWC.
2. Regarding 270-day conditions for HCAs and 18-month conditions
for non-HCAs:
a. Revise the existing reference to cracks and include crack
anomalies greater than 50 percent of wall thickness or the tool's
maximum measurable depth if it is less than 50 percent;
b. Allow for an industry recognized engineering analysis to
determine those dents that are non-injurious and require no further
investigation; and
c. 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 MOP at the location of the anomaly.
3. Add a ``Scheduled condition:''
a. Anomalies that do not meet the 270-day or the 18-month repair
criteria but have the possibility to grow before the next segment
inspection are subject to predictive modeling of remaining strength;
and
b. Investigate in the years prior to the next inspection if the
predicted burst pressure is less than 1.1 times the MOP at the location
of the anomaly.
In this final rule, PHMSA considered the recommendations of the
LPAC and adopted them as PHMSA deemed appropriate. To summarize, the
major changes PHMSA has made in this rule that deviate from the LPAC
recommendations are as follows: (1) PHMSA has added an additional
requirement that operators notify the appropriate PHMSA Region Director
when they are unable to inspect infrastructure impacted by extreme
weather within 72 hours; (2) PHMSA has removed the phrase ``other
similar event'' from the extreme weather inspection requirements; (3)
PHMSA has changed a word in the regulatory text for non-HCA
assessments, to provide that operators must assess ``line pipe''
(instead of ``pipelines defined under Sec. 195.1'') not subject to the
IM requirements at Sec. 195.452; (4) PHMSA has restricted the non-HCA
periodic assessment requirement to onshore, piggable, line pipe only,
which removed the proposed assessment requirement for covered offshore
lines and for regulated rural gathering lines; (5) PHMSA has removed
the leak detection requirement for rural regulated gathering lines at
Sec. 195.11; and (6) PHMSA declined to move forward with the repair
criteria and timelines as proposed for both HCAs and non-HCAs and has,
instead, reverted to the existing non-IM repair language in Sec.
195.401(b)(1) and the existing IM repair language at Sec. 195.452(h).
In the comments section, for each major topic of this final rule, PHMSA
broadly discusses specific amendments proposed during the meeting and
the corresponding discussion. PHMSA also discusses the instances where
PHMSA did not adopt the specific recommendations of the LPAC.

IV. Analysis of Comments and PHMSA Response

On October 13, 2015, PHMSA published an NPRM (80 FR 61609)
proposing several amendments to 49 CFR part 195. The NPRM proposed
amendments addressing the following areas:
(1) Reporting requirements for gravity lines.
(2) Reporting requirements for gathering lines.
(3) Inspections of pipelines following extreme weather events.
(4) Periodic assessments of pipelines not subject to IM.
(5) Repair criteria.
(6) Expanded use of leak detection systems.
(7) Increased use of in-line inspection tools.
(8) Clarifying other requirements.
Seventy organizations and individuals submitted comments in
response to the NPRM, including public representatives, private
citizens, industry service providers, individual pipeline operators,
and trade associations representing pipeline operators. Some of the
comments PHMSA received in response to the NPRM were comments beyond
the scope or authority of the proposed regulations. The absence of
amendments in this proceeding involving other pipeline safety issues
(including several topics listed in the ANPRM) does not mean that PHMSA
determined additional rules or amendments on other issues are not
needed. Such issues may be the subject of other existing

[[Page 52275]]

rulemaking proceedings or future rulemaking proceedings.
The remaining comments reflect a wide variety of views on the
merits of particular sections of the NPRM. The substantive comments
received on the NPRM are organized by topic below and are discussed in
the appropriate section with PHMSA's response and resolution to those
comments.

A. Reporting Requirements for Gravity Lines

1. PHMSA's Proposal
Gravity lines, pipelines that carry product by means of gravity,
are currently exempt from PHMSA regulations. Many gravity lines are
short and within tank farms or other pipeline facilities; however, some
gravity lines are longer and can build up large amounts of pressure
because they traverse areas with significant elevation changes, which
could have significant consequences in the event of a release.
For PHMSA to effectively analyze gravity line safety performance
and risk, PHMSA needs basic data about those pipelines. PHMSA has the
statutory authority to gather data for all pipelines (49 U.S.C.
60117(b)), and that authority was not affected by any of the provisions
in the 2011 Pipeline Safety Act. Accordingly, PHMSA proposed to add
Sec. 195.1(a)(5) to require that the operators of all gravity lines
comply with requirements for submitting annual, safety-related
condition, and incident reports.
2. Summary of Public Comment
PHMSA received comments from trade organizations, citizen groups,
and individuals on the scope and format of the reporting requirements.
To reduce the reporting burden, industry representatives (API-AOPL, the
GPA Midstream Association (GPA) and Energy Transfer Partners (ETP))
recommended that PHMSA create a new abbreviated annual report with
input from operators to separate the reporting of pipeline data for
regulated pipelines and those not currently subject to 49 CFR part 195.
Specifically, API noted that pipelines not currently covered under part
195 (gravity lines) are not subject to operator qualification, control
room management, leak detection, and HCA requirements, and therefore
those areas should be excluded from reporting. The Texas Pipeline
Association requested that reporting be limited to annual and incident
reports, a suggestion also supported by the ETP. API-AOPL commented
that industry experience indicates that the cost and time burdens
associated with the reporting requirements for gravity lines exceeded
the cost estimate cited by PHMSA in the NPRM.
The Environmental Defense Center requested that the reporting
requirements include the location, operation, condition, and history of
the pipelines, and multiple citizen groups requested that GIS mapping
be required for pipelines. In addition to GIS mapping information, the
Western Organization of Resource Councils and the Alliance for Great
Lakes et al. recommended that PHMSA also require pipeline operators to
meet minimum safety standards for all pipelines, a comment echoed by
numerous other citizen groups and individuals. These commenters also
requested that inspection reports, notices of violation, and similar
documents be made readily available to the public.
Trade organizations made additional comments regarding the
applicability and implementation timeline for the reporting
requirements. API-AOPL and other industry representatives requested
that the data collection be narrowed, such that it would apply only to
those gravity lines that could present a risk to the public, which: (1)
Travel outside of facility boundaries for at least 1 mile, (2) operate
at a specified minimum yield strength level of twenty percent or
greater, and (3) are not otherwise exempted in Sec. 195.1(b). On this
same basis, Denbury Resources added a request to exempt CO2
pipelines. Finally, API-AOPL requested that PHMSA extend the proposed
implementation period to 1 year after the effective date of the final
rule.
During the February 1, 2016, meeting, the LPAC recommended that
PHMSA modify the NPRM to (1) require reporting from gravity pipeline
operators using streamlined forms, (2) not require integration of
gravity lines into NPMS, (3) provide exceptions for lower-risk
pipelines (e.g., intra-plant lines), and (4) set a 1-year
implementation period for the annual reporting requirement and a 6-
month implementation period for the accident reporting requirement.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the scope and timing of the requirements for gravity lines.
After considering these comments and LPAC input, PHMSA is modifying the
exception for gravity lines at Sec. 195.1 as it pertains to reporting
requirements. This change will allow PHMSA to require operators of
gravity lines to report information annually, starting 1 year from the
rule's effective date, and to report accidents and safety-related
conditions starting 6 months from the rule's effective date. PHMSA
considers these deadlines practicable in view of the limited scope of
the information requested for these lines.
PHMSA focused collection on those data elements that will enable
the agency to assess the risk posed by these lines and determine
whether requirements that are more stringent are warranted in the
future. To facilitate reporting and address commenters' concerns about
providing clear instructions on data elements that operators must fill
out for gravity lines, PHMSA has modified its existing reporting form
to provide clear instructions, including skip patterns, for relevant
sections. In response to API's specific suggestions regarding operator
qualification, control room management, leak detection, and HCA
reporting, these revisions exempted gravity lines from any fields that
involve ``Could Affect HCA'' data. This targeting of the information
collection request will reduce the burden associated with providing the
information, as was requested by commenters. PHMSA recognizes that
operators who are not currently submitting data will have to register
with PHMSA to obtain an Operator Identification Number (OPID) under
Sec. 195.64, but the associated burden is minimal; PHMSA estimates
that fewer than 10 operators would need to submit information for
gravity lines. PHMSA estimates the total reporting burden at 66 hours
per year, on average.
During the LPAC meeting, the committee reached consensus on
requiring gravity line operators to report safety-related conditions.
These conditions could lead to significant consequences and are
important data points for PHMSA to determine whether additional gravity
line regulations may be necessary in the future.
As explained previously, the purpose of the information collection
is to support evaluation of the risk posed by gravity lines on the
public. With this goal in mind, PHMSA is receptive to commenters who
noted that pipelines located within the confines of a facility or in
close proximity (within 1 mile) to a facility and do not cross a
waterway currently used for commercial navigation pose a lower risk to
the public and the environment. PHMSA has decided to exempt these lines
from the reporting requirements. The language for this exception is
similar to the language of an existing exception for low-stress
pipelines at Sec. 195.1.
Further safety-related condition reporting exceptions at Sec.
195.55(b) will help minimize the reporting burdens for

[[Page 52276]]

operators. In the NPRM, PHMSA did not intend to propose requiring
mapping of gravity lines at this time and therefore is finalizing the
rule without this requirement. PHMSA understands commenters' concerns
that gravity line NPMS data submissions could be costly and burdensome.
However, as PHMSA is not requiring these submissions as a part of this
final rule's reporting requirements, the cost and burden of these
submissions were not and should not be considered as a part of the
cost-benefit analysis. If PHMSA determines, following analysis of the
data received on gravity lines, that mapping of these lines or
expanding reporting applicability to lines exempted in this final rule
would be beneficial to improve public safety or protect the
environment, it may consider additional requirements in a future
rulemaking.
Similarly, PHMSA is not requiring telephonic reporting of accidents
involving gravity lines at this time but may reassess this requirement
in a future rulemaking if analyses of the data suggest that doing so
would enhance prevention, preparedness, and response to hazardous
liquid releases from gravity lines.
Comments relating to public reporting and the reporting of specific
pipeline attributes discussed issues that PHMSA did not propose in the
NPRM and are therefore out-of-scope and could not be considered for
this rulemaking. Similarly, comments discussing minimum safety
standards be applied to gravity lines were also out-of-scope because
they requested more stringent requirements than what PHMSA proposed in
the NPRM.

B. Reporting Requirements for Gathering Lines

1. PHMSA's Proposal
In the NPRM, PHMSA also proposed to extend the reporting
requirements of 49 CFR part 195 to all hazardous liquid gathering
lines. Recent data indicates that PHMSA regulates less than 4,000 miles
of the approximately 30,000 to 40,000 miles of onshore hazardous liquid
gathering lines in the United States.\39\ That means that about 90
percent of the onshore gathering line mileage is not currently subject
to any minimum Federal pipeline safety standards. Congress also ordered
the review of existing State and Federal regulations for hazardous
liquid gathering lines in the Pipeline Safety Act of 2011, to prepare a
report on whether any of the existing exceptions for these lines should
be modified or repealed, and to determine whether hazardous liquid
gathering lines located offshore or in the inlets of the Gulf of Mexico
should be subjected to the same safety standards as all other hazardous
liquid gathering lines. Based on the study titled ``Review of Existing
Federal and State Regulations for Gas and Hazardous Liquid Gathering
Lines'' \40\ that was performed by the Oak Ridge National Laboratory
and published on May 8, 2015, PHMSA proposed additional regulations to
help ensure the safety of hazardous liquid gathering lines.
---------------------------------------------------------------------------

\39\ GAO-12-388: ``Pipeline Safety: Collecting Data and Sharing
Information on Federally Unregulated Gathering Pipelines Could Help
Enhance Safety,'' March 2012, pg. 7; https://www.gao.gov/assets/590/589514.pdf.
\40\ https://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/report_to_congress_on_gathering_lines.pdf.
---------------------------------------------------------------------------

For PHMSA to effectively analyze safety performance and risk of
gathering lines, we need basic data about those pipelines. PHMSA has
statutory authority to gather data for all gathering lines (49 U.S.C.
60117(b)). Accordingly, PHMSA proposed to add Sec. 195.1(a)(5) to
require that the operators of all gathering lines (whether onshore,
offshore, regulated, or unregulated) comply with requirements for
submitting annual, safety-related condition, and incident reports.
2. Summary of Public Comment
PHMSA received comments on hazardous liquid gathering lines that
echoed those for gravity lines. Citizen groups and individuals again
requested that the requirements for these lines include GIS mapping and
minimum safety standards; that the reporting include location,
operation, condition, and history; and that inspection reports, notices
of violation, and similar documents be made available to the public.
Trade organizations again commented on compliance costs and recommended
that the reporting requirement be limited to annual and incident
reports with an abbreviated form, have a phase-in implementation over 1
year, and exempt lower-risk pipelines. Specifically, API noted again
that, as rural gathering lines are not subject to operator
qualification, control room management, leak detection, and HCA
requirements, those areas should be excluded from reporting.
Trade organizations also made several additional recommendations
related to the scope of applicability, the scope of requirements, and
implementation. The Independent Petroleum Association of America (IPAA)
commented that PHMSA exceeds its authority in requiring operators of
gathering lines to submit annual, safety-related condition, and
incident reports. The GPA and other organizations noted that PHMSA did
not fully account for the burden increase and cost of the reporting
requirements for gathering lines in the preliminary RIA. The GPA
recommended that information requested under Sec. 195.61 and Sec.
195.64 be excluded from data collection. Numerous trade organizations
identified accident reporting for these lines as costly and
duplicative. The Louisiana Mid-Continent Oil and Gas Association
(LMOGA) commented that most, if not all accident information requested
for gathering lines is already required to be reported under other
existing Federal and State regulations, and the GPA recommended that
information collected through an abbreviated Annual Report could be
paired with Accident Reporting on Form F 7000-1 (rev 7-2014). LMOGA
also recommended that mapping of gathering lines not be required
because of incidental environmental impacts on wetlands, permitting,
and resource costs for teams to enter wetlands and track these lines.
The Offshore Operators Committee (OOC) requested that PHMSA make
clear in the final rule that the agency's intent is not to have the
proposed reporting requirements apply to gathering lines offshore
within State waters that are currently not regulated by PHMSA or the
Bureau of Safety and Environmental Enforcement (BSEE) or to other
gathering lines that are regulated by BSEE.
Finally, commenters asked for implementation periods that ranged
from 1 year (API-AOPL) to 10 years (Enterprise Products Partners) after
the effective date of the rule.
During the meeting on February 1, 2016, the LPAC recommended that
PHMSA modify the NPRM to (1) require reporting from gathering pipeline
operators using streamlined forms and (2) set a 1-year implementation
period for the annual reporting requirement and a 6-month
implementation period for the accident reporting requirement.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the scope and timing of the requirements for gathering lines.
Regarding the comment that the proposed reporting requirement of Sec.
195.1(a)(5) exceeds PHMSA's statutory authority, PHMSA notes that the
Federal Pipeline Safety Statutes state, in relevant part, ``[t]he
Secretary may require owners and operators of gathering lines to
provide the Secretary

[[Page 52277]]

information pertinent to the Secretary's ability to make a
determination as to whether and to what extent to regulate gathering
lines.'' 49 U.S.C. 60117(b). PHMSA has determined that, in order to
decide whether and to what extent to regulate gathering lines, as
permitted by Congress, PHMSA requires pertinent information about those
pipelines, including elements of the data contained in annual, safety-
related condition, and incident reports. With this reporting
requirement, PHMSA is not encroaching on the States' regulatory
authority, nor creating new jurisdiction. Rather, PHMSA is collecting
pertinent information to determine if future regulation is necessary
for the statutory purpose of promoting pipeline safety.
More specifically, PHMSA is collecting items in the annual report
that primarily include the mileage count for those gathering lines
currently unregulated, the diameters of those lines, and whether they
are operating at greater or less than 20 percent SMYS. The goal of
collecting this specific information is to provide PHMSA with a better
understanding of the scope of the Nation's gathering pipeline
infrastructure. As previously stated, recent data indicates PHMSA
regulates only approximately 4,000 miles of the estimated 30,000 to
40,000 miles of onshore hazardous liquid gathering lines in the United
States. That means that as much as 90 percent of the onshore gathering
line mileage is not currently subject to any minimum Federal pipeline
safety standards, and little is known about that mileage.
In requiring accident reports for otherwise unregulated gathering
lines, PHMSA is collecting data that includes the underlying cause for
the accident, where the accident was located and how it was reported to
the operator, and a value for any property damage caused. This data
will be essential to understanding and managing risk. PHMSA uses
information reported by pipeline operators to identify trends, provide
performance measures, and understand the causes and consequences of
pipeline incidents. Reporting requirements are in place for all
pipelines except for the gravity and gathering pipelines addressed by
this final rule. Each year, the U.S. Coast Guard's National Response
Center receives several notifications of hazardous liquid releases
involving ``gathering lines,'' but details on these releases are not
sufficient to understand the factors that contributed to the releases
and the damages, or to evaluate whether the lines involved are
gathering lines over which PHMSA has jurisdiction.\41\ The reporting
requirements for gathering lines will help PHMSA have a more complete
understanding of the risks these lines may pose.
---------------------------------------------------------------------------

\41\ NRC data for 2010 through 2014 show 116 incidents
categorized as ``pipeline'' incidents and that specifically include
the term ``gathering'' in the incident description. Many more
pipeline incidents could also be from gathering lines.
---------------------------------------------------------------------------

PHMSA notes that one of its challenges is to understand and target
risk, which requires a systematic approach to risk management,
including a ``comprehensive understanding of the factors contributing
to risk and the ability to focus resources in those areas that pose the
greatest risk.'' One of PHMSA's strategies for dealing with this
challenge is to improve data collection and analysis, collect the right
data to evaluate risks from unregulated entities, and improve the
transparency of information and public awareness of pipeline and
hazardous materials safety issues. The long-term benefits of having
better information may include reducing incidents, enhancing incident
response, and increasing public confidence.
As such, PHMSA is finalizing the requirement for operators of
gathering lines to report information annually, starting 1 year from
the rule's effective date, and to report accidents and safety-related
conditions starting 6 months from the final rule's effective date.
PHMSA considers these deadlines practicable in view of the scope of the
information requested. To facilitate reporting and address commenters'
concerns about providing clear instructions on data elements that must
be filled out for gathering lines, PHMSA has modified its existing
reporting form to provide clear instructions, including skip patterns,
on the relevant sections that gathering line operators must fill out.
In response to API's specific suggestions regarding operator
qualification, control room management, leak detection, and HCA
reporting, these revisions exempted rural gathering lines from any
fields that involve ``Could Affect HCA'' data. PHMSA recognizes that
operators who are not currently submitting data will have to register
for an identifier, but PHMSA expects the burden on operators to do this
is small. In its analysis, PHMSA assumed that a majority of the
reporting of currently unregulated gathering lines would be done by
operators who already have OPIDs. PHMSA estimates that, at a minimum,
approximately 20 operators will need to submit information for
gathering lines for the first time, and another 56 operators will add
information about gathering lines to their existing annual reports.
PHMSA estimates the total reporting burden at 402 hours per year, on
average. See the revised RIA accompanying the final rule for additional
detail.
Some commenters requested that PHMSA clarify whether these
reporting requirements applied to offshore gathering lines in State
waters. As the purpose of the information collection is to evaluate the
public risk posed by gathering lines, PHMSA found it appropriate to
extend the reporting requirements to certain offshore gathering lines
in State waters.
In its proposal, PHMSA did not intend to require mapping or NPMS
submissions for gathering lines. Under 49 U.S.C. 60132, only
transmission line operators are required to submit mapping data for use
in the NPMS; PHMSA does not have the explicit authority to collect NPMS
data for gathering lines. PHMSA is therefore finalizing the rule
without imposing this requirement on operators of gathering lines.
Similar to requirements for gravity lines, PHMSA is not requiring
telephonic reporting of accidents involving gathering lines to PHMSA at
this time since such a requirement would not support the purpose of
this data collection effort, which is to enable PHMSA to evaluate risk
over time for potential future action. PHMSA notes that operators must
still report spills to the National Response Center and other relevant
authorities. PHMSA will reassess the utility of requiring notification
for incidents involving gathering lines in a future rulemaking if the
analyses suggest that such notifications would enhance prevention,
preparedness, and response to hazardous liquid releases from gathering
lines.
Certain commenters also stated their belief that PHMSA neglected to
account for the costs and burden associated with the initial compiling
of the data needed to complete the forms. In many cases, the commenters
suggested, information may not have been recorded or may not have been
provided during mergers or acquisitions. PHMSA noted in the RIA that it
expects operators to have the requested information readily available,
as it is essential for pipeline operation and safety. PHMSA allows
operators to enter ``unknown'' when values cannot be determined for
certain data fields. In the burden estimate, PHMSA allotted time for
operators to compile the proper data and organize it into the requested
format. See the RIA for further details. PHMSA did not impose minimum
safety standards on currently unregulated gathering lines, as some

[[Page 52278]]

commenters suggested, because the agency currently does not have data
to analyze what risk, if any, those lines may pose to surrounding
communities and environments. However, under these provisions, PHMSA
will gather data on unregulated gathering lines and will use that data
to determine whether additional safety regulations may be necessary.

C. Pipelines Affected by Extreme Weather and Natural Disasters

1. PHMSA's Proposal
Recent events demonstrate the importance of ensuring that our
Nation's waterways are adequately protected in the event of a natural
disaster or extreme weather. PHMSA is aware that responsible operators
might do such inspections; however, because it is not a requirement,
some operators do not. Therefore, PHMSA proposed to require that
operators perform an additional inspection within 72 hours after the
cessation of an extreme weather event such as a hurricane or flood, an
earthquake, a natural disaster, or other similar event.
Specifically, PHMSA proposed that an operator must inspect all
potentially affected pipeline facilities after an extreme weather event
to help ensure that no conditions exist that could adversely affect the
safe operation of that pipeline. The operator would be required to
consider the nature of the event and the physical characteristics,
operating conditions, location, and prior history of the affected
pipeline in determining the appropriate method for performing the
inspection required. The initial inspection must occur within 72 hours
after the cessation of the event, defined as the point in time when the
affected area can be safely accessed by available personnel and
equipment required to perform the inspection. Based on PHMSA's
experience and coordination with operators following natural disasters,
PHMSA has found that 72 hours is reasonable and achievable in most
cases. If an operator finds an adverse condition, the operator must
take appropriate remedial action to best ensure the safe operation of a
pipeline based on the information obtained as a result of performing
the inspection. PHMSA specifically asked for comments on how operators
currently respond to these events, what type of events are encountered,
and if a 72-hour response time is reasonable.
2. Summary of Public Comment
Some trade organizations recommended that certain requirements be
eliminated altogether or consolidated to reduce what they considered to
be duplicative of existing emergency planning requirements in Sec.
195.402(e)(4).
Commenters were nearly unanimous in requesting that PHMSA clarify
the definition of extreme weather event, the 72-hour timeline, and the
timeline for mitigating or repairing anomalies. The GPA recommended
that PHMSA either define exactly which events require response and
inspection or establish performance expectations without partially
defining the criteria, while the County of Santa Barbara recommended
that the proposed regulations specify a threshold at which action would
be required. Congresswoman Lois Capps (California) recommended that
PHMSA include definitions and/or citations of existing definitions for
qualifying events and the responsible party for such a determination.
Congresswoman Capps also recommended that PHMSA clarify the terminology
for an ``appropriate method for performing the inspection'' after the
event.
In addition to clarification of the definition of extreme weather
event, trade groups also requested clarification of the 72-hour
timeline following an extreme weather event, including how they would
determine the cessation of the event, what appropriate action they
would need to take following an event, and how to address the
possibility of continued danger facing personnel or issues with
availability of personnel and resources following an event.
API-AOPL recommended that PHMSA define cessation as the point in
time when no further threats to personnel safety or equipment exist in
the affected area, allowing for safe access by pipeline personnel and
equipment. They also recommended that the 72-hour window commence only
once personnel and equipment could safely access the affected area.
Citizen groups and individuals requested that operators be required
to proactively address known risks and vulnerabilities in advance of an
extreme weather event. For example, one organization recommended
additional requirements to identify areas that are particularly
vulnerable to extreme weather events or natural disasters, (e.g.,
stream crossings, and to develop proactive preventive measures.) The
Alaska Wilderness League et al. recommended mandatory prevention
measures that include shutting down pipeline operations in case of an
imminent flood to prevent spills such as the 2011 Exxon Mobil
Yellowstone River spill. Citizen groups also requested immediate
reporting to PHMSA when remedial action is required and that this
information be made publicly available. The Environmental Defense
Center requested that PHMSA provide specific, enforceable requirements
for shutdown or other remedial action should an inspection reveal
damage or anomalies, and that PHMSA clarify the type of events covered
and the inspection methodology required.
Finally, the OOC recommended that PHMSA coordinate with BSEE and
the U.S. Coast Guard for activities that occur after hurricanes.
During the meeting on February 1, 2016, the LPAC recommended that
PHMSA modify the NPRM to (1) include landslides as an extreme weather
event, (2) clarify that other similar events are those likely to damage
infrastructure, and (3) require operators to inspect all potentially
affected pipeline facilities to detect conditions that could adversely
affect the safe operation of the pipeline. The LPAC also recommended
that PHMSA modify the language regarding the inspection method to
require operators to consider the nature of the event and the physical
characteristics, operating conditions, location, and prior history of
the affected pipeline in determining the appropriate method for
performing the initial inspection to determine damage and the need for
additional assessments. Finally, the LPAC recommended that PHMSA
clarify that the inspection must commence within 72 hours after the
cessation of the event, which is defined as the point in time when the
affected area can be safely accessed by the personnel and equipment,
accounting for personnel and equipment availability.
3. PHMSA Response
PHMSA disagrees with the comments stating the provisions at Sec.
195.414 are unnecessary and duplicate operation and maintenance (O&M)
manual requirements already contained in the response plan requirements
under Sec. 195.402. While Sec. 195.402 does require that operators
include certain ongoing monitoring measures in their O&M manuals, the
proposed Sec. 195.414 is much more specific in requiring that
operators take appropriate remedial action to best ensure the safe
operation of a pipeline based on the information obtained as a result
of performing the post-event inspection required under paragraph (a) of
this section. This will ensure that operators take the prescribed
actions; having measures described in an operator's O&M manual, as
previously required, is not equivalent to action. PHMSA maintains that
separate and more specific requirements are

[[Page 52279]]

warranted to best ensure public safety and environmental protection
following extreme events. Additionally, PHMSA notes that reporting is
coordinated with BSEE, the U.S. Coast Guard, and other agencies under
existing notification procedures if the assessment determines there was
a release involving their areas of responsibility. Both 49 CFR parts
194 and 195 require operators to report spills to the National Response
Center.
PHMSA appreciates the feedback provided by the commenters regarding
the need for greater clarity in the definition of extreme events and
natural disasters and expectations on the timing and scope of post-
event inspections. In developing the requirements, PHMSA sought to
balance being explicit regarding the types of events that could
increase the risk of a release and therefore require inspections, with
providing sufficient flexibility to account for diverse geographical
and pipeline design factors. PHMSA recognizes that the language
recommended by the LPAC is useful in striking this balance and adopted
most its revisions in the final rule under Sec. Sec. 195.414(a), (b),
and (c). PHMSA is removing the language ``other similar event'' as
PHMSA found the phrase to be vague and unnecessary to accomplish the
goals of the provision but is maintaining the LPAC's recommended
language regarding the ``likelihood to damage infrastructure.'' Per the
finalized requirement, operators must inspect all potentially affected
pipeline facilities following extreme weather events or natural
disasters with the likelihood of damaging infrastructure, such as named
hurricanes or tropical storms; floods that exceed the high-water banks
of rivers, shorelines or creeks; and landslides or earthquakes
occurring within the area of a pipeline, in order to detect conditions
that could adversely affect the safe operation of that pipeline. As
discussed earlier in this document, the conditions that trigger this
requirement are those that have the potential to cause river scour,
soil subsidence, or earth movement, all of which can subject a pipeline
to additional external loads and forces and cause the pipeline to fail.
Pipeline operators are already required to understand and analyze the
impact such weather events and natural disasters may have on their
systems based the physical characteristics, operating conditions,
location, and prior history of susceptible pipelines.
PHMSA retained the remedial actions unchanged from the proposal.
While PHMSA intends for operators to inspect pipelines as soon as
possible after an event ends, PHMSA also agrees with commenters that
personnel safety is paramount. Accordingly, PHMSA clarified that the
cessation of the event occurs as soon as it is safe for personnel and
equipment to access the area. Operators are responsible for determining
when each site is safe enough for entry.
In response to commenters who sought greater flexibility in the
timing of the inspections by leaving it up to the operators, PHMSA
disagrees and maintains that setting clear and consistent timelines is
essential to ensuring that all operators detect and address any issues
promptly. The final rule does provide a fallback to operators who must
delay the start of actions beyond this time due to availability of
equipment, but these operators must notify the Regional Director. This
addition to the LPAC-approved language allows operators to retain
flexibility due to unavailable equipment, while ensuring accountability
and prompt action. PHMSA considers 72 hours to be a reasonable period
for mobilizing personnel and equipment following an event.
In response to commenters who expressed concerns that inspections
cannot be reasonably be completed within the 72-hour window, PHMSA
notes that the proposal did not require completion of the inspections
within 72 hours, and neither does the final rule; PHMSA recognizes that
this needed to be clarified in the rule text and has done so in the
final rule. The final rule accordingly describes the actions it expects
operators to perform, starting within 72 hours after the cessation of
the event. Recognizing that some actions will need to be site-specific,
PHMSA provides flexibility to operators to determine the measures that
are appropriate to the event, pipeline design, and circumstances.
PHMSA is receptive to the recommendation that operators should take
precautionary measures to minimize exposure in advance of and during an
extreme event (e.g., reducing operating pressure or shutting down a
pipeline), and notes that the current IM regulations require operators
to know and understand risks to their system, which includes the threat
of extreme events such as flooding or wind damage. To execute their IM
programs and assessments on non-HCA lines as per this final rule,
operators will need to have pipeline system information to address
risks to their systems. Operators will use the information they have
gathered on their entire pipeline system to monitor conditions and
determine any anticipated risks to their pipelines, including extreme
weather events. Given that the existing IM regulations require
preventive and mitigative measures for HCAs, which often include river
crossings, it is appropriate for this section to address post-natural
disaster inspections for damage specifically.

D. Periodic Assessment of Pipelines Not Subject to IM

1. PHMSA's Proposal
PHMSA proposed to require integrity assessments for pipeline
segments in non-HCAs. PHMSA believes that expanded assessment of non-
HCA pipeline segments areas will provide operators with valuable
information they may not have collected if regulations were not in
place; such a requirement would help ensure prompt detection and
remediation of corrosion and other deformation anomalies in all
locations, not just HCAs. Specifically, the proposed Sec. 195.416
would require operators to assess non-HCA (non-IM) pipeline segments
with an ILI tool at least once every 10 years, which allows operators
to prioritize HCA assessments. PHMSA proposed to allow other assessment
methods if an operator provides OPS with prior written notice that a
pipeline is not capable of accommodating an ILI tool. Such alternative
technologies would include hydrostatic pressure testing or appropriate
forms of direct assessment.
Although imposing the full set of IM requirements in Sec. 195.452
on non-HCA pipeline segments was not proposed, operators would be
required to comply with the other provisions in 49 CFR part 195 in
implementing the requirements in Sec. 195.416. That includes having
appropriate provisions for performing periodic assessments and any
resulting repairs in an operator's procedural manual (see Sec.
195.402); adhering to the recordkeeping provisions for inspections,
tests, and repairs (see Sec. 195.404); and taking appropriate remedial
action under proposed Sec. 195.422, which, based on the existing IM
repair criteria at Sec. 195.452(h), identified specific types of
anomalies and the timeframes by which they must be remediated.
Operators would also follow the requirements for ``discovery of
condition,'' where the discovery of a condition occurs when an operator
has adequate information to determine that a condition exists. The
operator must promptly, but no later than 180 days after an assessment,
obtain sufficient information about a condition to determine whether
the condition could adversely affect the safe operation of the
pipeline, unless 180 days is impracticable as determined by

[[Page 52280]]

PHMSA. PHMSA sought public comment on the alternatives it considered
under this specific proposal and on quantifying these alternatives in
the regulatory impact analysis.
2. Summary of Public Comment
Trade organizations offered comments and language revisions on the
methods and requirements included in the periodic assessments,
implementation period, inspection intervals, and exemptions for lower
risk pipelines. Enterprise Products Partners requested that operators
be afforded the latitude they have under current IM regulations to
determine the actual threats to pipeline integrity present on a given
segment and to tailor their integrity assessment program accordingly.
For instance, Enterprise suggested that PHMSA revise the proposal to
clarify that a crack tool is not required for every ILI assessment,
stating specifically that ``an additional ILI crack tool is beneficial
only when there is an identified threat to the pipeline segment that
could result in cracks, such as cyclic fatigue. Yet PHMSA proposes to
require a [crack tool] in all circumstances and on every pipeline
segment.'' Other trade organizations echoed this and requested that
PHMSA incorporate alternatives to ILI tools for periodic assessments
into the rule. Trade organizations also recommended that PHMSA ensure
the rule is consistent with existing IM rules, including the
reassessment intervals and implementation period. The Texas Pipeline
Association requested that reassessment intervals be based on sound
engineering judgement and industry consensus standards. Finally, trade
organizations recommend that PHMSA limit and specify the type of
pipelines to which the requirement would apply, with some commenters
requesting specific exemptions for short lines and CO2
pipelines. API-AOPL requested that PHMSA clarify that operators would
not need to run assessments on idle or out-of-service pipelines. API-
AOPL also requested that PHMSA clarify that it intends for the
requirements to include transmission lines only. Finally, the GPA
requested that PHMSA rely on American Society of Nondestructive Testing
(ASNT) ILI PQ as the standard for data analysis rather than the current
language ``qualified by knowledge, training, and experience.'' The GPA
submitted additional comments to PHMSA on March 24, 2016, expressing
concerns that PHMSA misrepresented aspects of this proposal during the
LPAC meeting. In the LPAC meeting the GPA claimed that PHMSA asserted
that currently regulated gathering lines are subject to assessments;
the GPA believes that this statement was inaccurate and led to a vote
by the committee that was not based on accurate facts. Further, the GPA
suggested that ``it is possible there are gathering lines in non-rural
areas which do not meet the Census Bureau definitions for high or other
population areas. Thus, when properly applying the regulations as
currently written, there are gathering lines, which are regulated by
PHMSA and its state partners for safety purposes that are not subject
to periodic assessments.''
Trade organizations also commented on the cost of expanding
requirements for pipelines located outside of HCAs. The Texas Pipeline
Association commented that raising the level of regulation on
facilities outside of HCAs will redirect resources from high-risk areas
to lower-risk areas. They requested that PHMSA consider the costs to
operators of the proposed changes related to facilities outside of
HCAs. The OOC also commented that offshore lines present unique
challenges that make them ill-fitted for ILI technology and hydrotests.
Other groups and individuals commented on the methods and
requirements included in the periodic assessments, inspection
intervals, and additional requirements. A 5-year inspection interval
was generally favored by citizen groups and individuals, including the
Alliance for Great Lakes Et al. Congresswoman Capps highlighted that a
3-year interval between inspections had proven to be inadequate to
detect corrosion that caused the Plains All American oil pipeline
rupture in May 2015. These commenters also requested clarification that
alternative methods of assessment must account for inspection along the
entire pipeline both inside and outside HCAs and expressed concern with
waivers for ILI tools or the use of direct assessment.
The NTSB requested that PHMSA harmonize the gas and liquid
regulations to the maximum extent practicable and cautioned that direct
assessment is an ineffective alternative technology for IM when
applying the 10-year assessment requirement for the integrity of an
entire pipeline. They recommended that the IM program encompass a broad
range of available IM technologies including, but not limited to, ILI,
magnetic flux leakage, ultrasonic testing, and tests directed at
determining the integrity of the pipe coating.
Finally, some citizen groups and individuals requested that
inspection reports be made publicly available and that operators be
required to submit primary inspection results and data to PHMSA. The
Environmental Defense Center recommended third-party verification of
inspection reports based on corrosion underreporting. These groups also
requested risk assessment on non-IM pipelines and annual inspections
for all federally regulated hazardous liquid pipelines.
During the February 1, 2016, meeting, the LPAC recommended PHMSA
modify the NPRM to clarify its application to pipelines regulated under
Sec. 195.1 that are not subject to the IM requirements in Sec.
195.452. The LPAC also made additional language recommendations to
clarify the method of the assessment when ILI tools are impracticable,
including pressure tests, external corrosion direct assessment, or
other technology that the operator demonstrates can provide an
equivalent understanding of the condition of the line pipe.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters. PHMSA
notes that the LPAC, with minor tweaks, found the provision for
requiring operators to perform these periodic assessments on all
covered pipelines not subject to the integrity management requirements
under Sec. 195.452 to be a cost-effective, practicable, and
technically feasible provision.
However, several commenters noted challenges and cost-benefit
concerns with assessing offshore lines and regulated rural gathering
lines as a part of this proposal. In this final rule, PHMSA is limiting
the assessment requirement to onshore, non-HCA, non-gathering lines
that can accommodate inline inspection tools.
Under the current regulations, PHMSA notes that approximately 45
percent of hazardous liquid pipelines are required to be assessed per
the IM requirements by being located within an HCA or because they can
affect an HCA. PHMSA has determined that, through this provision, most
onshore non-HCA mileage will be assessed at a consistent rate. Further,
as pipeline operators continue to replace pipe through modernization
projects and repairs, PHMSA assumes that virtually all the Nation's
pipeline mileage will be piggable within the next few decades.
In the NPRM, PHMSA did not intend for the requirements applicable
to lines outside of HCAs to be more stringent than those applicable to
lines in HCAs. PHMSA agreed with the commenters and the LPAC that it is
appropriate to provide the same flexibility for the assessment of lines
outside of HCAs as

[[Page 52281]]

lines within HCAs, but PHMSA notes that many of these concerns appeared
to be in response to PHMSA's requirement to assess all non-HCA lines,
even ones that were not readily piggable. As discussed above, this
final rule's non-HCA assessment requirement now applies to piggable,
onshore transmission line only. This final rule does allow operators to
use pressure testing, direct assessment, or other technology in cases
when in-line inspections are impracticable. PHMSA has determined that
ILI tools may not be available for all pipe diameters and threats being
assessed, and providing operators the ability to use these other
assessment methods on piggable lines is appropriate at this time.
Further, per the comments received from commenters, including API
and Enterprise, related to the use of crack tools, PHMSA has revised
the final rule, at both Sec. Sec. 195.416 and 195.452, to require
crack tools only when there is an identified or probable risk or threat
supporting their use. For example, if operators have identified a
pipeline segment with identified or probable risks or threats related
to corrosion and deformation anomalies, including dents, gouges, or
grooves, then the operator must assess that segment with a tool capable
of detecting those anomalies. Similarly, operators should assess
pipeline segments with an identified or probable risk or threat related
to cracks using a tool capable of detecting crack anomalies.
Essentially, operators should always be selecting an appropriate
assessment tool based on the pertinent threats to a given pipeline
segment that have been identified by an operator's risk assessment. An
operator's risk assessment should always be driving its integrity
assessments and the integrity management program. An operator cannot
properly maintain its pipeline if it does not know what threats to
which the pipeline is susceptible to and which tools the company should
be selecting to assess those threats. These threats can include, but
are not limited to, pipe that may have manufacturing defects or have
otherwise experienced in-service incidents.
Under the existing requirements of Sec. 195.452(c)(1) (after which
PHMSA modeled the new assessment requirements in Sec. 195.416),
operators must select an assessment method capable of assessing seam
integrity and of detecting corrosion and deformation anomalies if the
applicable pipe is low-frequency ERW pipe or lap-welded pipe
susceptible to longitudinal seam failure. PHMSA has interpreted and
intended the phrase ``susceptible to seam failure'' to apply to both
low-frequency ERW pipe and lap-welded pipe. In this final rule, PHMSA
has expanded the assessment provisions to require operators to use a
tool or tools capable of assessing seam integrity, cracking, and of
detecting corrosion and deformation anomalies on low-frequency ERW
pipe, pipe with a seam factor less than 1.0 (as defined in Sec.
195.106(e)) \42\)), or lap-welded pipe susceptible to longitudinal seam
failure. Certain stakeholders may interpret this requirement to mean
that these tools will need to be run on every segment of low-frequency
ERW pipe, pipe with a seam factor of less than 1.0, or lap-welded pipe.
However, PHMSA only explicitly requires the use of these tools for
segments of low-frequency ERW pipe, pipe with a seam factor less than
1.0, or lap-welded pipe when these types of pipe are determined by an
operator to be susceptible to longitudinal seam failure based on
excavation findings, examinations, leaks, failures, pressure tests,
inline inspections, other operating history, and the manufacturing
history of the pipe vintage and its history of seam leaks and failures.
---------------------------------------------------------------------------

\42\ 49 CFR 195.106(e) has seam factors for pipe seams that need
to be de-rated for maximum operating pressure determination. A de-
rated seam factor would be below 1.0 and include furnace lap welded
and furnace butt welded pipe seams.
---------------------------------------------------------------------------

Similarly, PHMSA found that the proposed requirements for
``discovery of condition'' under Sec. 195.416 were more stringent than
the revisions proposed for Sec. 195.452. To be consistent with the
revised requirements under Sec. 195.452 regarding the discovery of
condition, the operator has 180 days to obtain sufficient information
on conditions and make the required determinations, unless the operator
can demonstrate that the 180-day timeframe is impracticable. In cases
where an operator does not have adequate information within 180 days
following an assessment, pipeline operators must notify PHMSA and
provide an expected date when that information will become available.
These revisions will provide consistency for the discovery of condition
across all regulated HCA and non-HCA lines.
PHMSA also agreed with the commenters and the LPAC that it is
necessary to clarify which pipelines fall under the non-HCA assessment
requirements. However, upon further review, PHMSA found that adopting
the LPAC-recommended language for Sec. 195.416(a), by clarifying
application of this requirement to pipelines regulated under Sec.
195.1 that are not subject to the IM requirements in Sec. 195.452,
would extend this requirement beyond PHMSA's or the LPAC's intent and
would cover facilities not previously intended, such as pump stations.
Therefore, instead of strictly adopting the language proposed by the
LPAC, PHMSA is instead specifying that these requirements apply to
onshore, piggable line pipe not covered under the IM requirements,
including the relevant line pipe within pump stations, but not other
appurtenances and components like metering stations, tanks, etc.
Further, PHMSA is not requiring IM 5-year assessments but is requiring
operators to continue the implementation of the preventive and
mitigative measures under IM (Sec. 195.452(i)) for appurtenances,
pumps, tanks, etc., for these facilities that could affect a HCA. PHMSA
believes this clarification captures the intent of the LPAC members.
In response to the GPA's suggestion for an alternative standard for
data analysis, PHMSA's existing process for data analysis has been
through a rigorous rulemaking process. PHMSA is not incorporating
alternative standards into this rule making that were not included at
an earlier rulemaking stage and were not subject to public comment.
Regarding the GPA's other concern as to whether PHMSA provided the
LPAC with inaccurate information concerning the extent to which
operators are already required to perform assessments on gathering
lines versus the new assessment requirements PHMSA was proposing in the
NPRM, PHMSA notes that on pages 180 and 181 of the LPAC meeting
transcript PHMSA clearly states that it is proposing subjecting
currently regulated rural gathering lines to periodic assessment and
repair requirements in Sec. Sec. 195.416 and 195.422, saying, ``When
it comes to the gathering lines that we don't currently regulate,
[that] the regulations don't currently address, the only requirements
we're applying will be the reporting requirements that we discussed
prior. In the [NPRM], when it came to regulated rural gathering lines,
we proposed to subject them to the assessment requirements in [Sec.
195.]416 and [Sec. 195.]422. There's actually a proposal in the NPRM
to link the two sections together, but it would not require that lines
that are currently, today, not regulated to be assessed.'' The
statement by PHMSA at the LPAC meeting that the GPA questions states
that regulated rural gathering lines have an assessment requirement in
the NPRM as opposed to currently unregulated gathering lines, which do
not. Further discussion and voting at the LPAC meeting indicated that
the committee members fully

[[Page 52282]]

understood PHMSA's proposal, with committee members clarifying the
definition by asking it to be revised to ``transmission and regulated
gathering lines'' and noting ``there's clarity with this [definition]
now.''
Regarding the GPA's other comment on the possibility of the
existence of gathering lines in non-rural areas that are not assessed,
PHMSA notes this is incorrect. Currently, the only regulated gathering
lines that are not subject to assessment requirements are regulated
rural gathering lines, which, per their name, are in rural areas. Under
existing Sec. 195.1(a)(4), any onshore gathering lines located in non-
rural areas and gathering lines located in Gulf of Mexico inlets are
covered by 49 CFR part 195, and if these gathering lines are within
HCAs or could affect HCAs, they are subject to the full IM program
requirements, including integrity assessments, under the current Sec.
195.452. As defined in Sec. 195.2, a ``rural area'' means ``outside
the limits of any incorporated or unincorporated city, town, village,
or any other designated residential or commercial area such as a
subdivision, a business or shopping center, or community development.''
To exist outside of a ``rural area'' as that term is defined under
Sec. 195.2 (i.e., a ``non-rural'' pipeline), a pipeline would have to
be inside (rather than outside) the limits of any incorporated or
unincorporated city, town, etc. Per the definition of an HCA at Sec.
195.450, a pipeline in such an area would be in an HCA, and therefore
would be regulated and subject to assessment requirements. Therefore,
with the exception of regulated rural gathering lines, operators should
be assessing all other regulated gathering lines per their IM programs.
PHMSA does not agree with API-AOPL that clarification is needed in
the rule on the issue of ``idle'' pipelines. The Federal PSR list only
two statuses for a pipeline: (1) In-service/active; or (2)
``abandoned,'' which the PSR defines as ``permanently removed from
service.'' Although operators frequently refer to a pipeline that is
not being actively used as ``idle,'' PHMSA has no current operational
designation for an ``idle'' line. Unless they are abandoned in
accordance with applicable procedures, pipelines that are not currently
in use must meet all the requirements of the Federal PSR, including
compliance with IM regulations if those pipelines are in HCAs. On March
17, 2014, a pipeline leaked crude oil into a highly populated suburb of
Los Angeles, CA (Wilmington, CA), releasing an estimated 1,200 gallons
of oil.\43\ The pipeline was never purged and filled with inert
material as per the operator's procedures required by the regulations,
and the operator (who bought the pipeline from another operator),
believed the pipeline was ``abandoned.'' This demonstrates the fact
that pipelines that have been ``idled'' can still present a safety risk
and must be treated as active pipelines. Further, as operators can
restart ``idle'' lines and transport product later, it is important
that operators maintain these lines to the same level of safety and
standards as an active, in-service line. Accordingly, PHMSA expects
operators of ``idle'' lines to perform assessments and adhere to all
the applicable regulations based on the line's location.
---------------------------------------------------------------------------

\43\ Jeff Gottlieb: ``Phillips 66 oil line in Wilmington blamed
for 1,200-gallon spill,'' Los Angeles Times, March 18, 2014. https://articles.latimes.com/2014/mar/18/local/la-me-0319-crude-oil-20140319.
---------------------------------------------------------------------------

PHMSA considered the requests it received to make inspection
reports for non-HCA lines publicly available and to require third-party
inspection report verification. PHMSA determined that promulgating
those requirements would make assessing non-HCA lines more burdensome
than assessing HCA lines.
Regarding requests that PHMSA require non-HCA inspections at 5-year
intervals to ensure a larger number of populations and properties are
protected, PHMSA notes that setting the non-HCA assessment interval to
5 years would make it equal to that for lines in HCAs. Lowering the
non-HCA assessment period to any time below 5 years would make it more
stringent than the requirement for HCAs and would not allow operators
to prioritize those higher-consequence areas first. Similarly,
requiring a yearly inspection of all hazardous liquid pipelines, as
some commenters suggested, would be overly burdensome and would work
against risk-based prioritization.
Many commenters also requested that PHMSA require operators to
perform risk assessments on non-IM pipelines. As discussed in the
previous section on extreme weather events, PHMSA expects operators
will need to have a certain amount of information on their HCA and non-
HCA pipelines, including the environment in which they operate, for
them to properly assess risk and the current condition of their
pipeline system and to select the proper tool(s) for an adequate threat
analysis. Operators cannot properly perform assessments if they do not
know or understand the ``as-is'' state of their pipeline and any
potential or actual threats. This information is required to comply
with Sec. 195.401(a), which states that no operator may operate or
maintain its pipeline systems at a level of safety lower than that
required by subpart F of 49 CFR part 195 and the procedures it is
required to establish under Sec. 195.402(a). Therefore, PHMSA expects
operators will already be performing a level of risk analysis on non-
HCA lines as well as HCA lines.

E. IM and Non-IM Repair Criteria

1.a PHMSA's Proposal for Sec. 195.452 (IM Repairs)
In the NPRM, PHMSA proposed modifying criteria in Sec. 195.452(h)
for IM repairs to:
Categorize bottom-side dents with stress risers, pipe with
significant stress corrosion cracking, and pipe with selective seam
weld corrosion as immediate repair conditions;
Require immediate repairs whenever the calculated burst
pressure is less than 1.1 times MOP;
Eliminate the 60-day and 180-day repair categories; and
Establish a new, consolidated 270-day repair category.
1.b PHMSA's Proposal for Sec. 195.422 (Non-IM Repairs)
PHMSA also proposed to amend the requirements in Sec. 195.422 for
performing non-IM repairs by:
Applying the criteria in the immediate repair category in
Sec. 195.452(h); and
Establishing an 18-month repair category for hazardous
liquid pipelines that are not subject to IM requirements.
2. Summary of Public Comment
Citizen groups and individuals expressed concern with the changes
to the repair timeline categories. The Alliance for Great Lakes et al.
requested that PHMSA maintain the 180-day repair timeframe for all
repairs that are not classified as immediate, and the Pipeline Safety
Trust (PST) did not see justification for the 18-month and
``reasonable'' time frames added for repairing pipelines outside of
HCAs. API-AOPL requested a reasonable timeframe to address repairs in
offshore pipelines that considers the type of repair and permit that
might be involved. ETP recommended that PHMSA change the 270-day and
18-month criteria to 1-year and 2-year criteria to assist operators
with planning, budgeting, and scheduling.
Enterprise Products Partners suggested specific language to clarify
that Sec. 195.422 would apply only to pipelines not subject to IM
requirements in Sec. 195.452 and those determined not to have the
potential to affect HCAs.

[[Page 52283]]

API-AOPL also expressed concern that PHMSA might apply these criteria
beyond non-HCA transmission lines to gravity and gathering lines
located offshore and recommended explicit language to state that Sec.
195.422 does not apply to gravity or gathering lines. The GPA requested
that PHMSA clarify the applicability of this section to out-of-service,
``idle'' pipelines.
Commenters also asked for additional standards for conditions
triggering repairs. For example, one public safety organization
requested a more stringent standard for the amount of metal loss that
triggers ``immediate repair,'' whereas the Alliance for Great Lakes et
al. recommended that PHMSA establish standards for the prevention,
detection, and remediation of significant stress corrosion cracking and
stress corrosion cracking.
The IPAA commented that PHMSA did not address whether resources
exist to make the additional repairs that would be required, nor did it
demonstrate a nexus between existing risk and the more conservative
repair requirements that justify the potential costs, especially when
considering regulated gathering lines. The GPA requested documentation
on the basis for requiring the same repair criteria for non-gathering
lines as the repair criteria for pipelines affecting HCAs. Western
Refining recommended that PHMSA exempt pipeline segments that normally
operate at a low pressure from the pressure reduction requirement. API-
AOPL recommended that PHMSA add an immediate repair condition for crack
anomalies at a 70 percent nominal wall thickness and an 18-month repair
condition on dents with corrosion. API-AOPL also recommended that PHMSA
include a ``Scheduled Conditions'' repair condition for non-HCA lines,
which would require an operator to make a report prior to the year when
a calculation of the predicted remaining strength of the pipe
(including allowances for growth and tool measurement error) shows a
predicted burst pressure at less than 1.1 times the MOP at the location
of the anomaly. This recommendation aimed to mitigate the potential for
pressure-limiting, immediate features before the next ILI. Enterprise
Products Partners recommended language to provide operators with
flexibility to determine the severity of the reported metal loss
indication and its potential impact on the integrity of the pipeline by
setting the dent threshold as corroded areas deeper than 20 percent of
the nominal wall thickness or where an engineering analysis indicates a
reduction in the safe operating pressure of the dented area.
API-AOPL and AGA recommended eliminating the SCC and SSWC immediate
repair criteria. The AGA also requested that PHMSA allow pipeline
operators to prioritize the repair of HCA segments over non-HCA
segments. The GPA was also concerned that PHMSA's definition of SCC was
based on the use of the word ``significant,'' because the term is
subjective and PHMSA's proposed descriptors do not include all the
variables that influence SCC behavior and is therefore very incomplete
for assigning an ``actionable'' status for all instances.
The PST requested that PHMSA change Sec. 195.563(a) to require
that constructed, relocated, replaced, or otherwise changed pipelines
must have cathodic protection within 6 months instead of 1 year, and
they also requested that PHMSA require operators to know what type of
pipe is in the ground and set the MOP appropriately, or test the pipe
with an appropriate hydrotest to demonstrate a safe MOP.
During the meeting of February 1, 2016, the LPAC recommended that
PHMSA modify the NPRM to include recognized industry engineering
analysis regarding dents and cracks to determine they are non-injurious
and do not require immediate repair, and to give full and equal
consideration to the stakeholder comments that were considered during
the LPAC discussion.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters. PHMSA
proposed revisions to the IM repair criteria to provide operators
greater flexibility regarding the repair timeframes for certain
anomalies, provide additional clarification regarding specific anomaly
types, and address pipe cracking issues both the agency and the NTSB
had identified following the incident near Marshall, MI, especially
regarding stress corrosion cracking and selective seam weld corrosion.
PHMSA also proposed to apply these changes with some modifications to
non-HCAs to provide flexibility to operators and allow the risk-based
prioritization of repairs.
PHMSA notes that the LPAC, with certain suggestions, found the
changes to both the non-HCA repair criteria and the HCA repair criteria
to be cost-effective, practicable, and technically feasible provisions,
and these provisions seemed to have wide stakeholder support following
the ANPRM stage. However, PHMSA determined as part of the review
process that it needs to gather additional data, including with respect
to cost-benefit information, and to assess new technologies and
practices before promulgating the proposed changes for non-HCA
pipelines in this final rule. Based on this, PHMSA has decided to
separate the repair-criteria provisions from this final rule and
intends to issue a supplemental notice of proposed rulemaking where
PHMSA would further analyze developing technology and practices,
anomaly types and repair timeframes, and engineering critical
assessment methods. This path will also provide commenters an
additional opportunity to provide input on an important part of the
regulations. PHMSA will incorporate any relevant discussion it would
have included in this section of this rulemaking when discussing repair
criteria in the supplemental notice. Therefore, for the purposes of
this final rule, PHMSA is retaining the existing non-IM repair language
at Sec. 195.401(b)(1) and the existing IM repair language at Sec.
195.452(h).
For non-IM pipelines, Sec. Sec. 195.401(b)(1), 195.585, and
195.587 outline the requirements for non-integrity management pipeline
repairs. Section 195.401(b)(1) requires operators that discover any
condition that could adversely affect the safe operation of its
pipeline system, they must correct the condition within a reasonable
time. However, if the condition is of such a nature that it presents an
immediate hazard to persons or property, the operator may not operate
the affected part of the system until it has corrected the unsafe
condition. For IM pipelines, PHMSA expects operators to continue to
follow the existing regulations in Sec. Sec. 195.401(b)(2) and
195.452(h) as they are written and repair the listed anomaly types
within the specified timeframes.

F. Leak Detection Requirements

1. PHMSA's Proposal
With respect to new hazardous liquid pipelines, PHMSA proposed to
amend Sec. 195.134 to require that all new lines be designed to have
leak detection systems, including pipelines located in non-HCA areas.
With respect to existing pipelines, 49 CFR part 195 contains
mandatory leak detection requirements for only those hazardous liquid
pipelines that could affect an HCA. Congress included additional
requirements for leak detection systems in section 8 of the 2011
Pipeline Safety Act. That legislation requires the Secretary to submit
a report to Congress, within 1 year of the enactment date, on the use
of leak detection systems, including an analysis of the technical
limitations and the practicability, safety benefits, and

[[Page 52284]]

adverse consequence of establishing additional standards for the use of
those systems. Congress authorized the issuance of regulations for leak
detection if warranted by the findings of the report.
Based on information available to PHMSA including post-accident
reviews and the Kiefner Report, PHMSA believes the need to strengthen
the requirements for leak detection systems is clear. In addition to
modifying Sec. 195.444 to require a means for detecting leaks on all
portions of a hazardous liquid pipeline system including non-HCA areas,
PHMSA proposed that operators perform an evaluation to determine what
kinds of systems must be installed to adequately protect the public,
property, and the environment. The proposed amendment to Sec. 195.11
extended these new leak detection requirements to regulated onshore
gathering lines.
2. Summary of Public Comment
Trade organizations expressed concerns with requiring operators of
gathering lines and certain non-gathering lines to install and maintain
leak detection systems. The GPA commented that PHMSA's proposal is not
appropriate for gathering lines at this time, citing findings of the
``Liquids Gathering Pipelines: A Comprehensive Analysis'' study,\44\
which concluded that (1) gathering lines present unique challenges to
leak detection technologies; (2) gathering lines are constantly
transition in flow, pressure, and line-packing; (3) benefits do not
justify the cost for leak detection systems applied to gathering lines;
and (4) there is a lack of demonstrated technology to reliably detect
spills. The IPAA noted that PHMSA should not proceed with expanding
leak detection systems because it had not performed an analysis of the
practicability of establishing technically, operationally, and
economically feasible standards for the capability of such systems to
detect leaks, and the safety benefits and adverse consequences of
requiring operators to use leak detection systems. The GPA also
recommended that PHMSA provide relief for short sections of pipeline
less than 1 mile in length and lines located within facilities where
they pose no risk to the public. API-AOPL and OOC requested
clarification that this section would not apply to offshore gathering
lines. The commenters requested implementation periods ranging between
5 years (API-AOPL) and 7 years (GPA). Finally, the Texas Pipeline
Association commented on the cost of complying with this regulation for
lines outside of HCAs and the redirection of resources from high-risk
areas to lower-risk areas that they allege would occur.
---------------------------------------------------------------------------

\44\ Energy and Environmental Research Center, University of
North Dakota, 2015, https://www.undeerc.org/bakken/pdfs/EERC%20Gathering%20Pipeline%20Study%20Final%20Dec15.pdf.
---------------------------------------------------------------------------

Citizen groups and other commenters requested minimum standards for
leak detection systems, and applicability to all hazardous liquids
lines. The Pipeline Safety Coalition recommended the inclusion of (1)
all existing hazardous liquids lines and all lines under construction
at rulemaking; (2) prescriptive standards for leak detection
classifications; (3) prescriptive standards for acceptable leak
detection procedures and devices; and (4) standards that are specific
to location, community, and environmentally sensitive areas. The
Alliance for Great Lakes et al. commented that computational pipeline
monitoring systems detect only large ruptures and involve significant
data interpretation and analysis. They expressed concerns regarding the
lack of system standards and guidance on how to assess the
effectiveness of a given leak detection system on a given pipeline due
to significant variations in pipeline design. The Environmental Defense
Center also recommended that automatic shutdown systems be required.
Beyond requirements for new pipelines, some commenters also
requested a clear schedule for leak detection system for pipelines
undergoing construction. For example, the NTSB urged PHMSA to include
language that specifies a distinct trigger date for leak detection
implementation on pipelines that have already started construction but
would not yet be operational when the new regulation becomes effective.
During the February 1, 2016, meeting, the LPAC recommended that
PHMSA modify the NPRM to (1) provide a 5-year implementation period for
existing pipelines and a 1-year implementation period for new pipelines
and (2) clarify that the expanded use of leak detection systems is not
applicable to offshore gathering pipelines.
3. PHMSA Response
PHMSA notes that commenters asserting PHMSA lacks the authority to
require leak detection systems because it did not first conduct a study
of these systems are incorrect. PHMSA did perform a leak detection
study (``Leak Detection Study--DTPH56-11-D000001'' \45\), as required
by section 8 of the 2011 Pipeline Safety Act, and submitted this study
to Congress on December 31, 2012. The study examined what methods and
measures operators were using as leak detection systems and the
limitations of those methods and measures. The study noted that ``due
to the vast mileage of pipelines throughout the Nation, it is important
that dependable leak detection systems are used to promptly identify
when a leak has occurred so that appropriate response actions are
initiated quickly. The swiftness of these actions can help reduce the
consequences of accidents or incidents to the public, environment, and
property.'' The study also noted that ``incidents described as leaks
can also have reported large release volumes.'' Based on the results of
the study, and due to pipeline accidents such as those near Marshall,
MI, and Salt Lake City, UT, which the study referenced, PHMSA concluded
that operators need to have an adequate means for identifying leaks to
better protect the public, property, and the environment. PHMSA
continues to foster leak detection technology improvements through
research and development projects, and PHMSA is also considering
pursuing rupture detection metrics in another rulemaking.
---------------------------------------------------------------------------

\45\ Kiefner & Associates, Inc.: ``Leak Detection Study,'' Final
Report No. 12-173, DTPH56-11-D-000001, December 10, 2012. https://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Press%20Release%20Files/Leak%20Detection%20Study.pdf.
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Recognizing that leak detection technology can be unreliable does
not imply that monitoring and leak detection are without value. The
value of lost product, negative impacts to the environment, loss of
pipeline functionality, spill remediation costs, and public perception
all impact decisions regarding the implementation of leak detection
systems. It is difficult to assign costs to many of these items. PHMSA
expects that the implementation of leak detection systems on non-HCA
pipelines will accelerate leak detection, lead to faster response and
spill containment, and reduce damages from hazardous liquid releases.
Given this information, PHMSA is finalizing a rule that requires
all new and existing lines, except for gathering lines not subject to
IM, regulated rural gathering lines, and offshore lines, to implement
leak detection systems. Since all lines within HCAs are already subject
to this requirement, the final rule affects pipelines outside of HCAs.

[[Page 52285]]

Commenters and LPAC members made persuasive arguments regarding the
technical challenges that exist for implementing leak detection systems
on offshore gathering lines due to the complex network of gathering
lines coming from offshore platforms and tremendous fluctuations in
flow controlled directly by production platforms. Further, commenters
had concerns that there was not adequate justification for leak
detection requirements on regulated rural gathering lines due to the
lack of incident history. PHMSA did not receive any data or comments
that contradicted these assertions; therefore, PHMSA is not extending
leak detection requirements to offshore gathering lines or regulated
rural gathering lines at this time. However, PHMSA does note that the
LPAC had no objections to extending this requirement to regulated rural
gathering lines and found the provision to be a cost-effective,
practicable, and technically feasible provision. Further, during the
12866 meeting between OIRA and API on December 12, 2016, API presented
data stating that operators agree with PHMSA's assumptions regarding
the use of leak detection systems on non-HCA pipelines. As such, PHMSA
may consider extending leak detection requirements to these lines in
the future.
PHMSA considered input from the comments and from the LPAC in
setting compliance periods of 1 year for all new lines, and 5 years for
all existing lines. Regarding concerns about compliance periods for
pipelines under construction, PHMSA considers any line that becomes
operational after the publication of this rule to be a new line and
will have 1 year to comply. PHMSA will consider pipelines that are
already operational before the publication of this rule as existing
lines, and those will have 5 years to comply. PHMSA determined that the
specified timelines are reasonable and practicable given that many
operators already implement leak detection systems on their entire
network across both HCA and non-HCA miles, and because many operators
are constructing and designing new lines with leak detection system
capabilities. Further, PHMSA assumes that the cost of extending
existing capabilities to non-HCA miles is minimal for systems already
equipped with SCADA sensors (see the RIA for details).
Certain commenters questioned the methods of leak detection that
PHMSA would require to comply with this provision. PHMSA notes that
negative pressure wave monitoring, real-time transient modelling, or
other external systems are not necessarily required to comply with the
rule. The costs of using or installing these leak detection system
components were not explicitly analyzed in the RIA; however, operators
may voluntarily choose to use these components, as well as any others,
to comply with the leak detection requirements of the rule.
PHMSA received several comments regarding leak detection system
performance criteria, valve spacing requirements, and automatic
shutdown capability, which were topics listed in the ANPRM. Due to the
complexity of these topics and the need for further study and public
comment, PHMSA is pursuing these topics in a separate rulemaking.\46\
---------------------------------------------------------------------------

\46\ ``Pipeline Safety: Amendments to Parts 192 and 195 to
Require Valve Installation and Minimum Rupture Detection
Standards,'' RIN: 2137-AF06.
---------------------------------------------------------------------------

G. Increased Use of ILI Tools in HCAs

1. PHMSA's Proposal
PHMSA proposed to require that all hazardous liquid pipelines in
HCAs and areas that could affect an HCA be made capable of
accommodating ILI tools within 20 years, unless the basic construction
of a pipeline will not accommodate the passage of such a device. The
current requirements for the passage of ILI devices in hazardous liquid
pipelines are prescribed in Sec. 195.120, which require that new and
replaced pipelines be designed to accommodate in-line inspection tools.
Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the
requirements for the passage of ILI tools to be extended to existing
hazardous liquid pipeline facilities, provided the basic construction
of those facilities can be modified to permit the use of smart pigs.
2. Summary of Public Comment
Trade organizations expressed concern that the NPRM would inhibit
operators from exercising their expert judgement in selecting an
assessment method and would be overly burdensome. API-AOPL and other
industry representatives requested that PHMSA not adopt this proposal
because it would require pipelines to incur extensive costs due to age,
design, and location of the pipelines, without demonstrating
commensurate benefits. They also requested that PHMSA remove the
requirement to petition for an exemption under Sec. 190.9 and instead
continue to allow operators to exercise their expertise and engineering
judgment in using the most effective and efficient methods of
evaluating the integrity of their facilities with prior notification to
OPS.
The IPAA and the American Gas Association (AGA) requested that
PHMSA review current studies or conduct an original study to determine
if ILI is appropriate to monitor pipeline corrosion given the current
state of technology. The AGA also requested that PHMSA provide
additional information on what the term ``basic construction'' meant in
the exemption from the ILI-capable requirement.
Conversely, citizen groups and individuals recommended that
operators use ILI more broadly. An organization representing public
safety and other commenters expressed concern with the length of the
20-year implementation period and the multiple exemptions such as where
the pipe is constructed in such a way that an ILI device cannot be
accommodated. Some of these commenters recommended instead that: (1)
PHMSA significantly reduce the timing of accommodating ILI devices,
perhaps to 5 years; (2) PHMSA require all new pipelines constructed in
HCAs to accommodate ILI devices immediately; (3) PHMSA reexamine and
tighten proposed exemptions; and (4) PHMSA establish standards for ILI
tools, including the detection of stress corrosion cracking.
Congresswoman Capps suggested that PHMSA could establish a shorter time
frame of 5 years with an extension possible upon request with
sufficient evidence for need and a provided plan of action to meet the
standard. The PST recommended that operators integrate close interval
survey results into ILI device findings.
Other groups commented on the tools used for inspection, the
compliance periods, and accountability. The Environmental Defense
Center requested that PHMSA require other inspection tools and methods,
such as hydrostatic pressure testing, where operators detect certain
types of anomalies and when these technologies can provide additional
information regarding the condition and vulnerabilities of a pipeline
system. The Alliance for Great Lakes et al. recommended that PHMSA
develop a framework that assigns different compliance periods for
pipelines based on factors such as age, leak history, corrosion,
environmental circumstances that could affect the pipeline, and other
aspects such as those typically reviewed in IM studies. Finally,
California Assembly Member Das Williams requested that operators be
required to submit ILI data to PHMSA for review and verification.
The NTSB recommended that PHMSA require owners/operators to develop
comprehensive implementation plans with transparent progress reporting
of

[[Page 52286]]

intermediate milestones to best ensure operators modify existing
pipelines to accommodate the passage of ILI devices within the 20-year
time limit. The NTSB also recommended that operators modify all newly
identified HCA segments to accommodate an internal inspection tool
according to an accelerated schedule, but not more than 5 years after
an operator identifies the HCA.
During the February 1, 2016, meeting, the LPAC recommended that
PHMSA adopt the proposed 20-year implementation period as feasible and
cost-effective. In a separate vote, the LPAC reached a tie on a 10-year
implementation period, which resulted in a failed motion. The LPAC also
recommended that Sec. 195.452(n) be modified to allow an operator to
file a petition that ILI tools cannot be accommodated when the operator
determines it would abandon or shut down a pipeline as a result of the
cost to comply.
3. PHMSA Response
PHMSA carefully considered input from commenters and the LPAC in
finalizing this rule, which requires that all HCA pipelines whose basic
construction would accommodate ILI tools be modified to permit the use
of ILI tools within 20 years. Examples of ``basic construction'' that
an operator may be able to show would not accommodate ILI tools include
short length, small diameter, diameter changes, low operating pressure,
low-volume flow, location, sharp bends, and terrain. PHMSA shares the
interest of commenters who requested expeditious upgrades to the
pipeline network to accommodate ILI tools. PHMSA maintains that ILI
tools are generally more effective than other methods at detecting
integrity issues. ILI tools take advantage of state-of-the-art
technological developments and allow operators to identify anomalies
and prioritize anomalies without interrupting services. ILI tools also
provide a higher level of detail than is possible using other testing
tools such as hydrotesting, which allow operators to determine whether
a required safety margin is met (i.e., pass/fail) but do not provide
information about the existence of anomalies that could deteriorate
over time between tests. PHMSA notes that the existing regulation
already requires new pipelines to be capable of accommodating ILI
tools, as certain commenters requested. Data from operators' pipeline
annual reports suggest that the vast majority of pipeline miles are
currently assessed using ILI tools. The mileage not assessed using
these tools is likely to consist of pipeline segments, such as small
diameter pipes, where ILI is impracticable using the current
technologies. Providing sufficient time for ILI tool accommodation
projects allows the industry to prioritize these projects based on age
or other factors, including the risk factors identified by the Alliance
for the Great Lakes in their comments; it also reduces the mileage of
pipeline potentially needing to be replaced before they have reached
their operational life. PHMSA determined that a 20-year timeline
strikes the appropriate balance between the need to make upgrades as
soon as possible to enable more effective integrity assessment
technologies, with the costs and operational practicalities of making
those changes. Given that a preponderance of HCA pipelines can already
accommodate ILI tools, exceptions available for specific pipeline
designs, operational benefits of ILI over other assessment methods, the
continued aging of unpiggable lines, and the 20-year compliance
deadline that will further reduce remaining mileage of old pre-ILI
pipeline, PHMSA determined that the final rule requirement to make
existing HCA pipelines able to accommodate ILI tools is unlikely to
impact any amount of the hazardous liquid pipeline infrastructure.\47\
Accordingly, PHMSA does not estimate any cost for this requirement.
---------------------------------------------------------------------------

\47\ In the RIA, PHMSA estimates that over 98 percent of
pipelines for which ILI is applicable likely are already able to
accommodate ILI tools. Given the factors listed here, PHMSA assumes
that essentially all HCA lines for which ILII is practicable are
currently, or will be within the next 20 years, piggable. Further
details are in the RIA for this rulemaking.
---------------------------------------------------------------------------

PHMSA will consider modifying its annual report form to have
hazardous liquid pipeline operators report data on what percentages of
their lines are piggable. In response to commenters who sought more
immediate implementation, PHMSA notes that inability to use ILI on a
pipeline segment does not mean that an operator has not assessed the
pipeline; the regulation requires that these pipelines be assessed
using alternative approaches, with hydrotesting being the most common
alternative. Data reviewed by PHMSA indicates that less than 1 percent
of HCA pipeline mileage is assessed using direct assessment methods.
Comments about seismicity considerations are addressed in the next
section.
In response to commenters who requested a specific deadline for
making lines in newly identified HCAs capable of accommodating ILI
tools, PHMSA notes that operators will have until the end of the 20-
year implementation period to make lines piggable. Operators who newly
identify HCAs in years 16-20 of the implementation period and after the
20-year implementation period will have 5 years from the date of the
HCA identification to make lines in those areas piggable.

H. Clarifying Other Requirements

1. PHMSA's Proposal
PHMSA also proposed several other clarifying changes to the
regulations that were intended to improve compliance. First, PHMSA
proposed to revise paragraph (b)(1) of Sec. 195.452 to better
harmonize the current regulations. The existing Sec. 195.452(b)(2)
requires that segments of new pipelines that could affect HCAs be
identified before the pipeline begins operations and Sec.
195.452(d)(1) requires that baseline assessments for covered segments
of new pipelines be completed by the date the pipeline begins
operation. However, Sec. 195.452(b)(1) does not require an operator to
draft its IM program for a new pipeline until 1 year after the pipeline
begins operation. Improved consistency would be beneficial, as the
identification of could affect segments and the performance of baseline
assessments are elements of the written IM program. PHMSA proposed to
amend the table in (b)(1) to resolve this inconsistency by eliminating
the 1-year compliance deadline for Category 3 pipelines. An operator of
a new pipeline would be required to develop its written IM program
before the pipeline begins operation.
PHMSA proposed to add additional specificity to Sec. 195.452(g) by
establishing several pipeline attributes that must be included in IM
information analyses and to explicitly require that operators integrate
analyzed information to help ensure they are properly evaluating
interacting threats. PHMSA also proposed that operators explicitly
consider any spatial relationships among anomalous information.
PHMSA also proposed that operators verify their segment
identification annually by determining whether factors considered in
their analysis have changed. The change that PHMSA proposed would not
require that operators automatically re-perform their segment analyses.
Rather, it would require operators to identify the factors considered
in their original analyses, determine whether those factors have
changed, and consider whether any such change would be likely to affect
the results of the original segment

[[Page 52287]]

identification. If so, the operator would be required to perform a new
segment analysis to validate or change the endpoints of the segments
affected by the change.
PHMSA also proposed to add an explicit reference clarifying that
the IM requirements apply to portions of pipeline facilities other than
line pipe. Unlike integrity assessments for line pipe, Sec. 195.452
does not include explicit deadlines for completing the analyses of
other facilities within the definition of ``pipeline'' or for
implementing actions in response to those analyses. While most
operators correctly treat any component that product moves through in
areas that could affect HCAs as subject to IM, PHMSA has reason to
believe that some operators have not completed analyses of their non-
pipe facilities such as pump stations and breakout tanks and have not
implemented appropriate protective and mitigative measures.
Section 29 of the 2011 Pipeline Safety Act states that ``[i]n
identifying and evaluating all potential threats to each pipeline
segment pursuant to parts 192 and 195 of title 49, Code of Federal
Regulations, an operator of a pipeline facility shall consider the
seismicity of the area.'' While seismicity is already mentioned at
several points in the IM program guidance provided in Appendix C of
part 195, PHMSA proposed to further comply with Congress's directive by
including an explicit reference to seismicity in the list of risk
factors that must be considered in establishing assessment schedules
(Sec. 195.452(e)), performing information analyses (Sec. 195.452(g)),
and implementing preventive and mitigative measures (Sec. 195.452(i))
under the IM requirements.
2. Summary of Public Comment
Trade organizations commented primarily on the implementation
period for PHMSA's clarifications on data integration and the
attributes and information required. Other trade associations joined
API-AOPL in requesting a 5-year implementation schedule for integrating
these specific attributes, including populating data into information
systems and validating the quality of the data process. The AGA
recommended that PHMSA focus on the analysis of information and
attributes rather than their integration.
Trade organizations also requested flexibility in developing the
attributes and information required in data analysis. The AGA requested
that operators independently develop the list of information and
attributes to be included in data analysis. They also commented that
there is no current regulatory requirement for an operator of hazardous
liquid or natural gas pipelines to maintain or utilize a GIS.
Finally, trade organizations expressed concern with changes to the
baseline assessment of newly constructed pipelines. API-AOPL requested
that PHMSA clarify that hydrostatic testing is an acceptable method of
meeting this requirement for new construction.
During the February 1, 2016, meeting, the LPAC recommended that
PHMSA modify the NPRM to require data integration to begin in year one,
with all attributes completed within 3 years.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters. As
discussed at the LPAC meeting, integrating data is a key element and
concept of continuous improvement and IM. The requirement that
operators perform data integration has long been a part of IM program
requirements. The attributes that PHMSA proposed in the NPRM were
factors operators should have already been considering when assessing
risk to their pipelines--PHMSA is merely codifying them to better
ensure all operators are utilizing them. PHMSA understands that the
need for some operators to enhance their data systems to fit these
specific attributes will take some time and effort. Because of this,
PHMSA agrees with the LPAC that operators should be given a maximum of
3 years to fully comply and integrate all the proposed attributes into
their data integration systems, with implementation beginning once the
rule is published. However, this implementation period does not mean
operators should lapse in what they are currently required to perform
under Sec. 195.452(g). PHMSA expects operators to add the attributes
issued in this final rule to their current data integration systems and
efforts. While PHMSA is sympathetic to allowing operators more
flexibility with the attributes that should be considered for data
integration, experience has shown that PHMSA needs to prescribe a
common baseline set of attributes for operators to assess.
PHMSA agrees with commenters who believe hydrostatic testing is an
acceptable baseline assessment method for newly constructed pipelines
and is incorporating that option into this final rule. As operators are
required to conduct hydrostatic tests on all newly constructed
pipelines prior to operation, and PHMSA allows operators to use
hydrostatic testing for subsequent assessments, PHMSA has determined
this could eliminate additional duplicative baseline assessments and
reduce operator burden.

V. PIPES Act of 2016

On June 22, 2016, the President signed the PIPES Act of 2016,
Public Law 114-183, containing Sections 14 and 25, ``Safety Data
Sheets'' and ``Requirements for Certain Hazardous Liquid Pipeline
Facilities,'' respectively. The language in both Section 14 and Section
25 is self-executing, with Section 25 specifically amending the
Pipeline Safety Act at 49 U.S.C. 60109 by adding new paragraphs (g)
through (g)(4). To allow the timely implementation of these sections of
the PIPES Act of 2016 and to help ensure regulatory certainty, PHMSA
has determined that good cause exists for finding that notice and
comment on these provisions is impracticable and contrary to the public
interest and is subsequently incorporating them into this final rule.
Section 14 of the PIPES Act of 2016 requires owners and operators
of hazardous liquid pipeline facilities, following accidents involving
pipeline facilities that result in hazardous liquid spills and within 6
hours of a telephonic or electronic notice of the accident to the
National Response Center, to provide safety data sheets on any spilled
hazardous liquid to the designated Federal On-Scene Coordinator and
appropriate State and local emergency responders. PHMSA has
incorporated this requirement in a new Sec. 195.65 under the reporting
requirements of Subpart B.
Section 25 of the PIPES Act of 2016 applies to operators of any
underwater hazardous liquid pipeline facility located in an HCA that is
not an offshore pipeline facility and any portion of which is located
at depths greater than 150 feet under the surface of the water.
Operators of these facilities, notwithstanding any pipeline integrity
management program or integrity assessment schedule otherwise required
by the Secretary, must ensure that pipeline integrity assessments using
internal inspection technology appropriate for the pipeline's integrity
threats are completed not less often than once every 12 months; and
using pipeline route surveys, depth of cover surveys, pressure tests,
ECDA, or other technology that the operator demonstrates can further
the understanding of the condition of the pipeline facility, ensure
that pipeline integrity assessments are completed on a schedule based
on the risk that the pipeline facility poses to the HCA in which the
pipeline facility is located. PHMSA has incorporated these

[[Page 52288]]

requirements in a new Sec. 195.454 as an addition to the pipeline
integrity management requirements under subpart F.

VI. Section-by-Section Analysis

Sec. 195.1 Which pipelines are covered by this part?

Section 195.1(a) lists the pipelines that are subject to the
requirements in 49 CFR part 195, including gathering lines that cross
waterways used for commercial navigation as well as certain onshore
gathering lines (i.e., those that are in a non-rural area, that meet
the definition of a regulated onshore gathering line, or that are in an
inlet of the Gulf of Mexico). PHMSA has determined it needs additional
information about unregulated gathering lines to fulfill its statutory
obligations, and it has determined it needs additional information
about gravity lines to determine whether any safety regulations need to
be extended to these lines as well. Accordingly, this final rule
extends the reporting requirements in subpart B of part 195 to all
gravity and gathering lines (whether regulated, unregulated, onshore,
or offshore).

Sec. 195.2 Definitions

Section 195.2 provides definitions for various terms used
throughout part 195. On August 10, 2007, PHMSA published a policy
statement and request for comment on the transportation of ethanol,
ethanol blends, and other biofuels by pipeline (72 FR 45002). PHMSA
noted in the policy statement that the demand for biofuels was
projected to increase in the future because of several Federal energy
policy initiatives, and that the predominant modes for transporting
such commodities (i.e., truck, rail, or barge) would expand over time
to include greater use of pipelines. PHMSA also stated that ethanol and
other biofuels are substances that ``may pose an unreasonable risk to
life or property'' within the meaning of 49 U.S.C. 60101(a)(4)(B) and
accordingly these materials constitute ``hazardous liquids'' for
purposes of the pipeline safety laws and regulations.
PHMSA is modifying the definition of ``hazardous liquid'' in Sec.
195.2 to conform with 49 U.S.C. 60101(a)(4)(B) and clarify that the
transportation of biofuel by pipeline is subject to the requirements of
49 CFR part 195.

Section 195.3 What documents are incorporated by reference partly or
wholly in this part?

The incorporation by reference of NACE SP0102 and API RP 1130 was
previously approved by the Director of the Federal Register and is not
changed by this rule.

Section 195.13 What requirements apply to pipelines transporting
hazardous liquids by gravity?

Section 195.13 is added to subject gravity lines to the same
annual, accident, and safety-related condition reporting requirements
in subpart B of part 195 as other hazardous liquid pipelines.

Section 195.15 What reporting requirements apply to reporting-
regulated-only gathering lines?

Section 195.15 is added to subject otherwise unregulated rural
gathering lines and certain offshore lines in State waters to the
annual, accident and safety-related condition reporting requirements in
subpart B of part 195 as other hazardous liquid pipelines.

Section 195.65 Safety Data Sheets

Section 195.65 contains the requirements for providing safety data
sheets on spilled hazardous liquids following accidents. In accordance
with Section 14 of the PIPES Act of 2016, PHMSA is requiring owners and
operators of hazardous liquid pipeline facilities, following accidents
that result in hazardous liquid spills, to provide safety data sheets
on those spilled hazardous liquids to the designated Federal On-Scene
Coordinator and appropriate State and local emergency responders within
6 hours of a telephonic or electronic notice of the accident to the
National Response Center. This is a self-executing provision from the
PIPES Act of 2016 that PHMSA is incorporating into subpart B of the
hazardous liquid pipeline safety regulations.

Section 195.120 Passage of Internal Inspection Devices

Section 195.120 contains the requirements for accommodating the
passage of internal inspection devices in the design and construction
of new or replaced pipelines. PHMSA has decided that, in the absence of
an emergency, or where the basic construction makes that accommodation
impracticable, a pipeline should be designed and constructed to permit
the use of ILIs. Accordingly, this final rule repeals the provisions in
the regulation that allow operators to petition the Administrator for a
finding that the ILI compatibility requirement should not apply as a
result of construction-related time constraints and problems. The other
provisions in Sec. 195.120 are re-organized without altering the
existing substantive requirements.

Section 195.134 Leak Detection

Section 195.134 contains the design requirements for computational
pipeline monitoring leak detection systems. The final rule restructures
the existing requirements into paragraphs (a) and (c) and adds a new
provision in paragraphs (b) and (d) to ensure that all newly
constructed, covered pipelines are designed to include leak detection
systems based upon standards in section 4.2 of API 1130 or other
applicable design criteria in the standard.

Section 195.401 General Requirements

Section 195.401 prescribes general requirements for the operation
and maintenance of hazardous liquid pipelines. PHMSA is modifying the
pipeline repair requirements in Sec. 195.401(b). PHMSA is retaining,
without change, the requirements in paragraphs (b)(1) for non-IM
repairs and (b)(2) for IM repairs. A new paragraph (b)(3) is added,
however, to clearly require operators to consider the risk to people,
property, and the environment in prioritizing the remediation of any
condition that could adversely affect the safe operation of a pipeline
system, no matter whether those conditions are in HCAs or non-HCAs.

Section 195.414 Inspections of Pipelines in Areas Affected by Extreme
Weather and Natural Disasters

Extreme weather and natural disasters can affect the safe operation
of a pipeline. Accordingly, this final rule establishes a new Sec.
195.414 that requires operators to perform inspections after these
events and to take appropriate remedial actions.

Section 195.416 Pipeline Assessments

Periodic assessments, particularly with ILI tools, provide critical
information about the condition of a pipeline, but are only currently
required under IM requirements in Sec. Sec. 195.450 through 195.452.
PHMSA has determined that operators should be required to have the
information needed to promptly detect and remediate conditions that
could affect the safe operation of pipelines in all areas. Accordingly,
the final rule establishes a new Sec. 195.416 that requires operators
to perform an assessment, at least once every 10 years, of onshore
pipelines that can accommodate inline inspection tools and that are not
already subject to the IM requirements. This assessment must be
performed for the range of relevant threats to the pipeline segment
using an appropriate ILI tool(s) and

[[Page 52289]]

account for uncertainties in reported results. Operators must use a
method capable of assessing seam integrity and corrosion and
deformation anomalies when assessing LF-ERW pipe, lap-welded pipe, or
pipe with a seam factor of less than 1.0. In lieu of performing an ILI
assessment on their lines, operators can perform the assessment by
using a pressure test, external corrosion direct assessment, or other
technology (subject to prior notification, method being able to assess
the threat, and ``no objection'' by PHMSA) that can be demonstrated as
providing an equivalent understanding of the pipe's condition.
The regulation also requires that the results of these assessments
be reviewed by a person qualified to determine if any conditions exist
that could affect the safe operation of a pipeline; that such
determinations be made promptly, but no later than 180 days after the
assessment; that any unsafe conditions be remediated in accordance with
the repair requirements in Sec. 195.401(b)(1); and that all relevant
information about the pipeline be considering in complying with the
requirements of Sec. 195.416. Consistent with the requirements in the
revised Sec. 195.452(h)(2) regarding the discovery of condition, in
cases where the information necessary to make determination about
pipeline threats cannot be obtained within 180 days following the date
of inspection, pipeline operators must notify PHMSA and provide an
expected date when adequate information will become available.

Section 195.444 Leak Detection

Section 195.444 contains the operation and maintenance requirements
for Computational Pipeline Monitoring leak detection systems. PHMSA is
amending the PSR so that all covered hazardous liquid pipelines have a
leak detection system. Therefore, the final rule reorganizes the
existing requirements of the regulation into paragraphs (a) and (c),
and adds a new general provision in paragraph (b) that requires
operators to have leak detection systems on all covered pipelines and
to consider certain factors in determining what kind of system is
necessary to protect the public, property, and the environment.

Section 195.452 Pipeline Integrity Management in High Consequence Areas

Section 195.452 contains the IM requirements for hazardous liquid
pipelines that could affect a HCA in the event of a leak or failure.
The final rule clarifies the applicability of the deadlines in
paragraph (b) for the development of a written program for new
pipelines and low-stress pipelines in rural areas. The rule also makes
the following amendments to paragraphs (c) through (o):
Paragraph (c)(1)(i)(A) is amended to ensure that operators
consider uncertainty in tool tolerance in reviewing the results of ILI
assessments. The paragraph is also amended to be more consistent with
paragraphs at Sec. 195.416 by stating that pipeline segments with
identified or probable risks or threats related to cracks (such as at
pipe body and weld seams) based on the risk factors specified in
paragraph (e), an operator must use an ILI tool or tools capable of
detecting crack anomalies.
Paragraph (d) is amended to eliminate obsolete deadlines
for performing baseline assessments and to clarify the requirements for
newly identified HCAs. The deletion of these previous compliance dates
does not change or delete any associated recordkeeping requirements or
implement any new recordkeeping requirements. Operators should retain
the records they have used to show compliance regarding the baseline
assessment deadlines.
Paragraph (e)(1)(vii) is amended to include local
environmental factors, including seismicity, that might affect pipeline
integrity.
Paragraph (g) is amended to prescribe certain data points
and criteria that operators must consider in performing the information
analysis required to evaluate periodically the integrity of covered
pipeline segments.
Paragraph (h)(2) is amended to require that in those
situations where an operator must obtain adequate information within
180 days after an integrity assessment to determine whether an
anomalous condition could present a potential integrity threat of the
pipeline but the operator believes it is impracticable to obtain
sufficient information within that period, the operator must notify
PHMSA and provide an expected date when adequate information will
become available.
Paragraph (j) is amended to establish a new provision for
verifying the risk factors used in identifying covered segments on at
least an annual basis, not to exceed 15 months.
A new paragraph (n) is added to require that all pipelines
in areas that could affect an HCA be made capable of accommodating ILI
tools within 20 years, unless, subject to a petition and PHMSA
approval, the basic construction of a pipeline will not permit that
accommodation, the existence of an emergency renders such an
accommodation impracticable, or the operator determines it would
abandon or shut down a pipeline as a result of the cost to comply with
the requirement of this section. Paragraph (n) requires that pipelines
in newly identified HCAs after the 20-year period be made capable of
accommodating ILIs within 5 years of the date of identification or
before the performance of the baseline assessment, whichever is sooner.
Paragraph (o) is added to allow operators additional time
to integrate the additional information and attributes that PHMSA has
added to the information analysis required under paragraph (g)(1).
Finally, an explicit reference to seismicity is added to
factors that must be considered in establishing assessment schedules
under paragraph (e), for performing information analyses under
paragraph (g), and for implementing preventive and mitigative measures
under paragraph (i).

Section 195.454 Integrity Assessments for Certain Underwater Hazardous
Liquid Pipeline Facilities Located in HCAs

Section 195.454 contains additional assessment requirements for
operators of any underwater hazardous liquid pipeline facility located
in an HCA that is not an offshore pipeline facility and any portion of
which is located at depths greater than 150 feet under the surface of
the water. In accordance with section 25 of the PIPES Act of 2016,
PHMSA is requiring these operators to ensure that they complete
pipeline integrity assessments not less often than once every 12 months
using internal inspection technology appropriate for the integrity
threats to the pipeline and complete pipeline integrity assessments
using pipeline route surveys, depth of cover surveys, pressure tests,
external corrosion direct assessment, or other technology that the
operator demonstrates can further the understanding of the condition of
the pipeline facility, on a schedule based on the risk that the
pipeline facility poses to the HCA in which the pipeline facility is
located. This is a self-executing provision from the PIPES Act of 2016
that PHMSA is incorporating into subpart F of the hazardous liquid
pipeline safety regulations.

VII. Regulatory Notices

A. Statutory/Legal Authority for This Rulemaking

This final rule is published under the authority of the Federal
Pipeline Safety

[[Page 52290]]

Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes the Secretary
of Transportation to issue regulations governing design, installation,
inspection, emergency plans and procedures, testing, construction,
extension, operation, replacement, and maintenance of pipeline
facilities, as delegated to the PHMSA Administrator under 49 CFR 1.97.
PHMSA is revising the ``Authority'' entry for part 195 to include a
citation to a provision of the Mineral Leasing Act (MLA), specifically,
30 U.S.C. 185(w)(3). Section 185(w)(3) provides that ``[p]eriodically,
but at least once a year, the Secretary of the Department of
Transportation shall cause the examination of all pipelines and
associated facilities on Federal lands and shall cause the prompt
reporting of any potential leaks or safety problems.'' The Secretary
has delegated this responsibility to PHMSA (49 CFR 1.97). PHMSA has
traditionally complied with Sec. 185(w)(3) through the issuance of its
pipeline safety regulations, which require annual examinations and
prompt reporting for all or most of the pipelines they cover. PHMSA is
making this change to be consistent with and make clear its long-
standing position that the agency complies with the MLA through the
issuance of pipeline safety regulations.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

This final rule is a significant regulatory action under Section
3(f) of Executive Order 12866 (58 FR 51735), and therefore was reviewed
by the Office of Management and Budget. This final rule is significant
under the Regulatory Policies and Procedures of the Department of
Transportation (44 FR 11034) because of substantial congressional,
State, industry, and public interest in pipeline safety.
In the regulatory analysis, PHMSA discusses the alternatives to the
amended requirements and, where possible, provides estimates of the
benefits and costs for specific regulatory requirements by individual
requirement areas. The regulatory analysis provides PHMSA's best
estimate of the impact of the final rule requirements. As shown in the
table below, PHMSA estimated the total annual costs of the rule at
$19.5 million using a 3 percent discount rate and $21.4 million using a
7 percent discount rate.
Due to data limitations, PHMSA evaluated the benefits of the final
rule qualitatively. Overall, the rule will provide direct benefits
through avoiding damages from hazardous pipeline incidents that may be
prevented through earlier detection of threats to pipeline integrity
from corrosion or following extreme weather events, and through
enhancing the ability of PHMSA and pipeline operators to evaluate
risks. As context, operator-reported data for hazardous liquid
incidents that occurred between 2010 and 2017 show reported average
annual damages of $91.6 million for pipelines outside HCAs and $265.8
million for pipelines inside HCAs, or about $815 and $3,222 per mile of
hazardous liquid pipeline, respectively. These damages are only a
fraction of the total social costs of hazardous liquid releases but
indicate the potential magnitude of benefits derived from preventing
pipeline failures.
---------------------------------------------------------------------------

\48\ Numbers in this table may not sum due to rounding.

Annualized Costs and Benefits by Requirement Area (2017$) \48\
----------------------------------------------------------------------------------------------------------------
Annual costs \1\
Final rule requirement area -------------------------------------------------------- Benefits
3% Discount rate 7% Discount rate
----------------------------------------------------------------------------------------------------------------
1. Reporting requirements for $5,000.................... $5,000.................... Better risk
gravity lines. understanding and
management.\2\
2. Reporting requirements for $75,000................... $76,000................... Better risk
gathering lines. understanding and
management.\3\
3. Inspections of pipelines in Minimal................... Minimal................... Additional clarity and
areas affected by extreme certainty for pipeline
weather events \4\. operators.
4. Assessments of onshore $6,467,000................ $6,467,000................ Avoided incidents and
pipelines that are not already damages through
covered under the IM program detection of safety
using ILI every 10 years 5 6. conditions.\7\
5. IM repair criteria \8\...... $0........................ $0........................ $0.
6. LDSs on pipelines located $8,652,000................ $10,508,000............... Reduced damages through
outside HCAs \6\. earlier detection and
response.\9\
7. Increased use of ILI tools Minimal................... Minimal................... Improved detection of
\10\. pipeline flaws.\10\
8. Clarify certain IM plan $4,269,000................ $4,343,000................ Reduced damages through
requirements.. prevention and earlier
detection and
response.\11\
--------------------------------------------------------------------------------
Total...................... $19,468,000............... $21,399,000............... Reduced damages from
avoiding and/or
mitigating hazardous
liquid releases.
----------------------------------------------------------------------------------------------------------------
\1\ Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in
individual sections of the document. One-time costs are annualized over a 10-year period using discount rates
of 3 percent and 7 percent.
\2\ Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow
pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of
this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated
gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
101 gallons per year to generate benefits that equal the costs.
\3\ The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated
gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
1,493 gallons per year to generate benefits that equal the costs.
\4\ To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting
inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not
reflected in this analysis.
\5\ PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not
currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios:
(1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a
scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two
scenarios are $0 and $12.9 million, respectively.
\6\ Excludes gathering lines.
\7\ Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to
prevent 12 incidents for benefits to equate costs.
\8\ PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or
benefits.

[[Page 52291]]

\9\ As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an
average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of
approximately $382,179, not including additional damages and costs that are excluded or underreported in the
incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents.
\10\ Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the
extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be
minimal due to baseline prevalence of ILI-capable pipelines in all areas.
\11\ The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids
cannot be quantified but could vary in frequency and size depending on the types of failures that are averted.
Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected
to enhance an operator's ability to identify and address risk. The societal costs associated with incidents
involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates
for this requirement are equivalent to the average damages from less than three such incidents. This is
relative to an annual average of 161 incidents in HCAs between 2010 and 2017.

Overall, factors such as increased safety, public confidence that
all pipelines are regulated, quicker discovery of leaks and mitigation
of environmental damages, and better risk management are expected to
yield benefits that exceed or otherwise justify the costs. A copy of
the final RIA has been placed in the docket. Pursuant to the
Congressional Review Act (5 U.S.C. 801 et seq., the Office of
Information and Regulatory Affairs designated this rule as not a
``major rule,'' as defined by 5 U.S.C. 804(2).

C. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs

The final rule is an Executive Order 13771 regulatory action.
Details on the estimated costs of this final rule can be found in the
rule's economic analysis.

D. Executive Order 13132: Federalism

This final rule has been analyzed in accordance with the principles
and criteria contained in Executive Order 13132 (``Federalism''). This
final rule does not adopt any regulation that has substantial direct
effects on the states, the relationship between the national government
and the states, or the distribution of power and responsibilities among
the various levels of government. It does not adopt any regulation that
imposes substantial direct compliance costs on state and local
governments. Therefore, the consultation and funding requirements of
Executive Order 13132 do not apply.

E. Regulatory Flexibility Act

The Regulatory Flexibility Act of 1980 (Pub. L. 96-354) (RFA)
establishes ``as a principle of regulatory issuance that agencies shall
endeavor, consistent with the objectives of the rule and of applicable
statutes, to fit regulatory and informational requirements to the scale
of the businesses, organizations, and governmental jurisdictions
subject to regulation. To achieve this principle, agencies are required
to solicit and consider flexible regulatory proposals and to explain
the rationale for their actions to assure that such proposals are given
serious consideration.''
The RFA covers a wide range of small entities, including small
businesses, not-for-profit organizations, and small governmental
jurisdictions. Agencies must perform a review to determine whether a
rule will have a significant economic impact on a substantial number of
small entities. If the agency determines that it will, the agency must
prepare a regulatory flexibility analysis as described in the RFA.
However, if an agency determines that a rule is not expected to
have a significant economic impact on a substantial number of small
entities, section 605(b) of the RFA provides that the head of the
agency may so certify and a regulatory flexibility analysis is not
required. The certification must include a statement providing the
factual basis for this determination, and the reasoning should be
clear.
PHMSA performed a screening analysis of the economic impact on
small entities. The screening analysis is available in the docket for
the rulemaking. PHMSA estimates that compliance costs may exceed 1
percent of sales for 23 to 31 of the estimated small businesses and may
exceed 3 percent of sales for 9 to 10 small businesses. The higher
number of affected small businesses assumes that the operator incurs
costs for all applicable requirements.
Given the small number and percentage of small businesses affected,
the small sales test ratios, and the noted flexibility, PHMSA
determined that the final rule will not have a significant impact on a
substantial number of small entities.\49\
---------------------------------------------------------------------------

\49\ Based on SBA (2013), including criteria developed by other
agencies.
---------------------------------------------------------------------------

Therefore, I certify that this action does not have a significant
economic impact on a substantial number of small entities.

F. National Environmental Policy Act

PHMSA analyzed this final rule in accordance with section 102(2)(c)
of the National Environmental Policy Act (42 U.S.C. 4332), the Council
on Environmental Quality regulations (40 CFR parts 1500 through 1508),
and DOT Order 5610.1C, and has determined that this action will not
significantly affect the quality of the human environment. An
environmental assessment of this rulemaking is available in the docket.

G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

This final rule has been analyzed in accordance with the principles
and criteria contained in Executive Order 13175 (``Consultation and
Coordination with Indian Tribal Governments''). Because this final rule
does not have Tribal implications and does not impose substantial
direct compliance costs on Indian Tribal governments, the funding and
consultation requirements of Executive Order 13175 do not apply.

H. Paperwork Reduction Act

Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. PHMSA estimates the proposals in this rulemaking will impact
the following information collections:
``Transportation of Hazardous Liquids by Pipeline: Recordkeeping
and Accident Reporting'' identified under Office of Management and
Budget (OMB) Control Number 2137-0047;
``Reporting Safety-Related Conditions on Gas, Hazardous Liquid, and
Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities''
identified under OMB Control Number 2137-0578;
``Integrity Management in High Consequence Areas for Operators of
Hazardous Liquid Pipelines'' identified under OMB Control Number 2137-
0605;
``Pipeline Safety: Reporting Requirements for Hazardous Liquid
Pipeline Operators: Hazardous Liquid Annual Report'' identified under
OMB Control Number 2137-0614;
``National Registry of Pipeline and LNG Operators'' identified
under OMB Control Number 2137-0627; and
``Operator Notifications--Alternate Pressure Testing Method''
identified under OMB Control Number 2137-0630.
PHMSA will submit an information collection revision request to OMB
for

[[Page 52292]]

approval based on the requirements in this rule. These information
collections are contained in the Federal Pipeline Safety Regulations,
49 CFR parts 190-199. The following information is provided for each
information collection: (1) Title of the information collection; (2)
OMB control number; (3) Current expiration date; (4) Type of request;
(5) Abstract of the information collection activity; (6) Description of
affected public; (7) Estimate of total annual reporting and
recordkeeping burden; and (8) Frequency of collection. The information
collection burden for the following information collections are
estimated to be revised as follows:
1. Title: Transportation of Hazardous Liquids by Pipeline:
Recordkeeping and Accident Reporting.
OMB Control Number: 2137-0047.
Current Expiration Date: 08/31/2020.
Abstract: This information collection covers the collection of
information from owners and operators of hazardous liquid pipelines. To
ensure adequate public protection from exposure to potential hazardous
liquid pipeline failures, PHMSA collects information on reportable
hazardous liquid pipeline accidents. 49 CFR 195.54 requires hazardous
liquid operators to file an accident report, as soon as practicable,
but not later than 30 days after discovery of the accident, on DOT Form
7000-1 whenever there is a reportable accident the characteristics of
an operator's pipeline system. The final rule will require operators of
both gravity lines and gathering lines to be subject to these accident
reporting requirements. Thus, PHMSA expects an additional 28 HL
pipeline operators (23 gathering line operators and approximately 5
gravity line operators) to be added to the reporting community.
If the frequency of accidents is the same for non-regulated
gathering lines and gravity lines as it is for transmission lines,
approximately 4 to 6 percent of these newly regulated operators will
submit an accident report in any given year. Of the 23 new gathering
line operators, PHMSA expects 5 accident reports to be filed per year.
Of the 5 new gravity line operators, PHMSA expects 1 accident report to
be filed per year. This results in an added burden of 6 new accident
reports per year at 10 hours per report for a total added burden of 60
hours for accident reporting.
The final rule will also amend the Pipeline Safety Regulations
(PSR) in 49 CFR 195.65 to require all owners and operators of hazardous
liquid pipeline facilities, following accidents that result in
hazardous liquid spills, to provide safety data sheets on those spilled
hazardous liquids to the designated Federal On-Scene Coordinator and
appropriate State and local emergency responders within 6 hours of a
telephonic or electronic notice of the accident to the National
Response Center. PHMSA expects hazardous liquid operators to file
approximately 406 accident reports per year. This will result in an
added burden of 406 new notifications per year. PHMSA expects that it
will take operators 30 minutes to conduct the required task. This will
result in an added burden of 406 records at .5 hours per record for a
total added burden of 203 hours for safety data sheet notifications
recordkeeping.
This information collection is being revised to account for the
additional burden that will be incurred because of these new
provisions.
Affected Public: Owners and operators of hazardous liquid
pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 1,644.
Total Annual Burden Hours: 52,692.
Frequency of Collection: On occasion.
2. Title: Reporting Safety-Related Conditions on Gas, Hazardous
Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas
Facilities.
OMB Control Number: 2137-0578.
Current Expiration Date: 8/31/2022.
Abstract: 49 U.S.C. 60102 requires each operator of a pipeline
facility (except master meter operators) to submit to U.S. DOT a
written report on any safety-related condition that causes or has
caused a significant change or restriction in the operation of a
pipeline facility or a condition that is a hazard to life, property or
the environment.
This rule will require operators of both gravity lines and
gathering lines to be subject to safety-related condition reporting.
While there is no guarantee that each of the newly covered operators
will incur a safety-related condition, it is a possibility. As a
result, PHMSA plans to include an additional 28 hazardous liquid
pipeline operators (23 gathering line operators and approximately 5
gravity line operators) in this reporting community. PHMSA estimates
that it takes each operator 6 hours to complete a safety-related
condition report. The addition of the 28 newly covered operators will
result in 28 additional responses and an added burden of 168 hours (28
operators * 6 hours).
This information collection is being revised to account for the
additional burden that will be incurred by newly regulated entities.
Operators currently submitting annual reports will not be otherwise
impacted by this rule.
Affected Public: Owners and operators of hazardous liquid
pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 174.
Total Annual Burden Hours: 1,044.
Frequency of Collection: On occasion.
3. Title: Hazardous Liquid Pipeline Assessment Requirements.
OMB Control Number: 2137-0605.
Current Expiration Date: 09/30/2022.
Abstract: Owners and operators of hazardous liquid pipelines are
required to have continual assessment and evaluation of pipeline
integrity through inspection or testing, as well as remedial preventive
and mitigative actions. Because of this rulemaking action, in cases
where a determination about pipeline threats has not been obtained
within 180 days following the date of inspection, pipeline operators
are required to notify PHMSA in writing and provide an expected date
when adequate information will become available. PHMSA estimates that
only 1 percent of repair reports (approx. 74) will require these
notifications each year. Operators are authorized to send the
notification, via email, to PHMSA's Information Resources Manager.
PHMSA estimates that it will take operators 30 minutes to create and
send each notification resulting in an overall burden increase of 37
hours annually.
Hazardous liquid pipeline operators are also required to notify
PHMSA when they are unable to assess their pipeline via an in-line
inspection. Operators who choose to use an alternate assessment method
must demonstrate that their pipeline is not capable of accommodating an
in-line inspection tool and that the use of an alternative assessment
method will provide a substantially equivalent understanding of the
condition of the pipeline. PHMSA estimates that operators will submit
approximately 10 notifications each year regarding these conditions.
Further, PHMSA estimates that each notification will take 10 hours,
which includes the time to assemble the necessary information to
demonstrate that the pipeline is not capable of accommodating an ILI
tool and specify that the alternative assessment method will provide a
substantially equivalent understanding of the pipeline. This will
result in an annual notification burden of 100 hours.
The overall annual burden increase for this information collection
is 84 responses and 137 hours. PHMSA requests the title of this
information collection, previously ``Integrity Management in High
Consequence Areas for Operators of Hazardous Liquid Pipelines,'' be
changes to better align with the requested data.

[[Page 52293]]

Affected Public: Owners and operators of Hazardous Liquid
Pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 287.
Total Annual Burden Hours: 325,607.
Frequency of Collection: Annually.
4. Title: Pipeline Safety: Reporting Requirements for Hazardous
Liquid Pipeline Operators: Hazardous Liquid Annual Report.
OMB Control Number: 2137-0614.
Current Expiration Date: 01/31/2022.
Abstract: Owners and operators of hazardous liquid pipelines are
required to provide PHMSA with safety-related documentation relative to
the annual operation of their pipeline. The provided information is
used to compile a national pipeline inventory, identify safety
problems, and target inspections.
Due to provisions within this final rule, approximately 5 gravity
line operators and 23 gathering line operators will be required to
submit annual reports to PHMSA. PHMSA estimates the burden associated
with annual reporting activities to be approximately 19 hours per
report, composed of 12 hours of a compliance officer's time and 7 hours
of a secretary/administrative assistant's time. The newly regulated
gravity and gathering line operators will cause an added burden of 28
new annual reports per year at 19 hours per report for a total added
burden of 532 hours for annual reporting.
This information collection is being revised to account for the
additional burden that will be incurred by the newly affected
operators. Operators currently submitting annual reports will not be
otherwise impacted by this rule.
Affected Public: Owners and operators of hazardous liquid
pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 475.
Total Annual Burden Hours: 8,989.
Frequency of Collection: Annually.
5. Title: National Registry of Pipeline and LNG Operators.
OMB Control Number: 2137-0627.
Current Expiration Date: 04/301/2022.
Abstract: The National Registry of Pipeline and LNG Operators
serves as the storehouse for the reporting requirements for an operator
regulated under or subject to reporting requirements of 49 CFR parts
191, 192, 193, or 195. The final rule requires operators of both
gravity lines and gathering lines to be subject to various reporting
requirements. Thus, approximately 5 gravity line operators and 23
gathering line operators will be required to register their pipeline
with the National Pipeline Registry and apply for an Operator
Identification number (OPID). PHMSA estimates that this activity will
take 1 hour per operator to register.
Gravity and gathering line operators will also be required to
notify PHMSA of certain changes made to their pipeline system when
applicable. PHMSA estimates that 5 percent (approximately 1) of these
newly regulated operators will make these notifications each year.
PHMSA estimates that this activity will take 1 hour per operator.
This information collection is being revised to account for the
additional burden (29 responses x 1 hour = 29 hours) that will be
incurred by the newly regulated operators. Operators currently
registered will not be otherwise impacted by this rule.
Affected Public: Natural gas, LNG, and hazardous liquid pipeline
operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 718.
Total Annual Burden Hours: 718.
6. Title: Hazardous Liquid Operator Notifications.
OMB Control Number: 2137-0630.
Current Expiration Date: N/A.
Abstract: The Pipeline Safety regulations contained within 49 CFR
part 195 require hazardous liquid operators to notify PHMSA in various
instances. 49 CFR 195.414 requires hazardous liquid operators who are
unable to inspect their pipeline facilities within 72 hours of an
extreme weather event to notify the appropriate PHMSA Region Director
as soon as practicable. PHMSA expects to receive 100 of these
notifications annually. PHMSA believes it will take operators
approximately 15 minutes (0.25 hours) to make this notification and
send it to the Regional Director electronically. PHMSA expects the
annual burden for this requirement to be 25 hours.
49 CFR 195.452 requires operators of pipelines that cannot
accommodate an in-line inspection tool to file a petition in compliance
with 49 CFR 190.9. PHMSA expects to receive 10 of these notifications
annually. PHMSA expects that it will take operators 10 hours to provide
records to demonstrate that their pipeline cannot accommodate an inline
inspection device for an overall annual burden of 100 hours for this
notification requirement.
Affected Public: Owners and operators of hazardous liquid
pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 110.
Total Annual Burden Hours: 125.
Frequency of Collection: Annually.
Requests for copies of these information collections should be
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline
Safety (PHP-30), Pipeline and Hazardous Materials Safety Administration
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-
0001, Telephone (202) 366-4595.
Comments are invited on:
(a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
(d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
Those desiring to comment on these information collections should
send comments directly to the Office of Management and Budget, Office
of Information and Regulatory Affairs, Attn: Desk Officer for the
Department of Transportation, 725 17th Street NW, Washington, DC 20503.
Comments should be submitted on or prior to October 31, 2019. Comments
may also be sent via email to the Office of Management and Budget at
the following address: [email protected]. OMB is required to
make a decision concerning the collection of information requirements
contained in this final rule between 30 and 60 days after publication
of this document in the Federal Register. Therefore, a comment to OMB
is best assured of having its full effect if received within 30 days of
publication.

I. Privacy Act Statement

Anyone is able to search the electronic form of all comments
received into any of our dockets by the name of the individual
submitting the comment (or signing the comment, if submitted on behalf
of an association, business, labor union, etc.). You may review DOT's
complete Privacy Act Statement in the Federal Register published on
April 11, 2000 (65 FR 19477), or at https://www.regulations.gov.

[[Page 52294]]

J. Regulation Identifier Number (RIN)

A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Federal Regulations. The
Regulatory Information Service Center publishes the Unified Agenda in
April and October of each year. The RIN contained in the heading of
this document may be used to cross-reference this action with the
Unified Agenda.

List of Subjects in 49 CFR Part 195

Incorporation by reference, Integrity management, Pipeline safety.

In consideration of the foregoing, PHMSA is amending 49 CFR part
195 as follows:

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
1. Revise the authority citation for part 195 to read as follows:

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
and 49 CFR 1.97.

0
2. Amend Sec. 195.1 by adding paragraph (a)(5) and revising paragraphs
(b)(2) and (b)(4) to read as follows:

Sec. 195.1 Which pipelines are covered by this part?

(a) * * *
(5) For purposes of the reporting requirements in subpart B of this
part, any gathering line not already covered under paragraphs (a)(1),
(2), (3) or (4) of this section.
(b) * * *
(2) Except for the reporting requirements of subpart B of this
part, see Sec. 195.13, transportation of a hazardous liquid through a
pipeline by gravity.
* * * * *
(4) Except for the reporting requirements of subpart B of this
part, see Sec. 195.15, transportation of petroleum through an onshore
rural gathering line that does not meet the definition of a ``regulated
rural gathering line'' as provided in Sec. 195.11. This exception does
not apply to gathering lines in the inlets of the Gulf of Mexico
subject to Sec. 195.413.
* * * * *

0
3. Amend Sec. 195.2 by revising the definition for ``Hazardous
liquid'' to read as follows:

Sec. 195.2 Definitions.

* * * * *
Hazardous liquid means petroleum, petroleum products, anhydrous
ammonia, and ethanol or other non-petroleum fuel, including biofuel,
which is flammable, toxic, or would be harmful to the environment if
released in significant quantities.
* * * * *

Sec. 195.3 [Amended]

0
4. In Sec. 195.3, amend paragraph (g)(3) by removing ``Sec. 195.591''
and adding ``Sec. Sec. 195.120 and 195.591'' in its place.

0
5. Add Sec. 195.13 to subpart A to read as follows:

Sec. 195.13 What requirements apply to pipelines transporting
hazardous liquids by gravity?

(a) Scope. Pipelines transporting hazardous liquids by gravity must
comply with the reporting requirements of subpart B of this part.
(b) Implementation period--(1) Annual reporting. Comply with the
annual reporting requirements in subpart B of this part by March 31,
2021.
(2) Accident and safety-related reporting. Comply with the accident
and safety-related condition reporting requirements in subpart B of
this part by January 1, 2021.
(c) Exceptions. (1) This section does not apply to the
transportation of a hazardous liquid in a gravity line that meets the
definition of a low-stress pipeline, travels no farther than 1 mile
from a facility boundary, and does not cross any waterways used for
commercial navigation.
(2) The reporting requirements in Sec. Sec. 195.52, 195.61, and
195.65 do not apply to the transportation of a hazardous liquid in a
gravity line.
(3) The drug and alcohol testing requirements in part 199 of this
subchapter do not apply to the transportation of a hazardous liquid in
a gravity line.

0
6. Add Sec. 195.15 to subpart A to read as follows:

Sec. 195.15 What requirements apply to reporting-regulated-only
gathering lines?

(a) Scope. Gathering lines that do not otherwise meet the
definition of a regulated rural gathering line in Sec. 195.11 and any
gathering line not already covered under Sec. 195.1(a)(1), (2), (3) or
(4) must comply with the reporting requirements of subpart B of this
part.
(b) Implementation period--(1) Annual reporting. Operators must
comply with the annual reporting requirements in subpart B of this part
by March 31, 2021.
(2) Accident and safety-related condition reporting. Operators must
comply with the accident and safety-related condition reporting
requirements in subpart B of this part by January 1, 2021.
(c) Exceptions. (1) This section does not apply to those gathering
lines that are otherwise excepted under Sec. 195.1(b)(3), (7), (8),
(9), or (10).
(2) The reporting requirements in Sec. Sec. 195.52, 195.61, and
195.65 do not apply to the transportation of a hazardous liquid in a
gathering line that is specified in paragraph (a) of this section.
(3) The drug and alcohol testing requirements in part 199 of this
subchapter do not apply to the transportation of a hazardous liquid in
a gathering line that is specified in paragraph (a) of this section.

0
7. Add Sec. 195.65 to subpart B to read as follows:

Sec. 195.65 Safety data sheets.

(a) Each owner or operator of a hazardous liquid pipeline facility,
following an accident involving a pipeline facility that results in a
hazardous liquid spill, must provide safety data sheets on any spilled
hazardous liquid to the designated Federal On-Scene Coordinator and
appropriate State and local emergency responders within 6 hours of a
telephonic or electronic notice of the accident to the National
Response Center.
(b) Definitions. In this section:
(1) Federal On-Scene Coordinator. The term ``Federal On-Scene
Coordinator'' has the meaning given such term in section 311(a) of the
Federal Water Pollution Control Act (33 U.S.C. 1321(a)).
(2) National Response Center. The term ``National Response Center''
means the center described under 40 CFR 300.125(a).
(3) Safety data sheet. The term ``safety data sheet'' means a
safety data sheet required under 29 CFR 1910.1200.

0
8. Revise Sec. 195.120 to read as follows:

Sec. 195.120 Passage of internal inspection devices.

(a) General. Except as provided in paragraphs (b) and (c) of this
section, each new pipeline and each main line section of a pipeline
where the line pipe, valve, fitting or other line component is replaced
must be designed and constructed to accommodate the passage of
instrumented internal inspection devices in accordance with NACE SP0102
(incorporated by reference, see Sec. 195.3).
(b) Exceptions. This section does not apply to:
(1) Manifolds;
(2) Station piping such as at pump stations, meter stations, or
pressure reducing stations;

[[Page 52295]]

(3) Piping associated with tank farms and other storage facilities;
(4) Cross-overs;
(5) Pipe for which an instrumented internal inspection device is
not commercially available; and
(6) Offshore pipelines, other than lines 10 inches (254
millimeters) or greater in nominal diameter, that transport liquids to
onshore facilities.
(c) Impracticability. An operator may file a petition under Sec.
190.9 for a finding that the requirements in paragraph (a) of this
section should not be applied to a pipeline for reasons of
impracticability.
(d) Emergencies. An operator need not comply with paragraph (a) of
this section in constructing a new or replacement segment of a pipeline
in an emergency. Within 30 days after discovering the emergency, the
operator must file a petition under Sec. 190.9 for a finding that
requiring the design and construction of the new or replacement
pipeline segment to accommodate passage of instrumented internal
inspection devices would be impracticable as a result of the emergency.
If PHMSA denies the petition, within 1 year after the date of the
notice of the denial, the operator must modify the new or replacement
pipeline segment to allow passage of instrumented internal inspection
devices.

0
9. Revise Sec. 195.134 to read as follows:

Sec. 195.134 Leak detection.

(a) Scope. This section applies to each hazardous liquid pipeline
transporting liquid in single phase (without gas in the liquid).
(b) General. (1) For each pipeline constructed prior to October 1,
2019. Each pipeline must have a system for detecting leaks that
complies with the requirements in Sec. 195.444 by October 1, 2024.
(2) For each pipeline constructed on or after October 1, 2019. Each
pipeline must have a system for detecting leaks that complies with the
requirements in Sec. 195.444 by October 1, 2020.
(c) CPM leak detection systems. A new computational pipeline
monitoring (CPM) leak detection system or replaced component of an
existing CPM system must be designed in accordance with the
requirements in section 4.2 of API RP 1130 (incorporated by reference,
see Sec. 195.3) and any other applicable design criteria in that
standard.
(d) Exception. The requirements of paragraph (b) of this section do
not apply to offshore gathering or regulated rural gathering lines.

0
10. In Sec. 195.401, add paragraph (b)(3) to read as follows.

Sec. 195.401 General requirements.

* * * * *
(b) * * *
(3) Prioritizing repairs. An operator must consider the risk to
people, property, and the environment in prioritizing the correction of
any conditions referenced in paragraphs (b)(1) and (2) of this section.
* * * * *

0
11. Add Sec. 195.414 to read as follows:

Sec. 195.414 Inspections of pipelines in areas affected by extreme
weather and natural disasters.

(a) General. Following an extreme weather event or natural disaster
that has the likelihood of damage to infrastructure by the scouring or
movement of the soil surrounding the pipeline, such as a named tropical
storm or hurricane; a flood that exceeds the river, shoreline, or creek
high-water banks in the area of the pipeline; a landslide in the area
of the pipeline; or an earthquake in the area of the pipeline, an
operator must inspect all potentially affected pipeline facilities to
detect conditions that could adversely affect the safe operation of
that pipeline.
(b) Inspection method. An operator must consider the nature of the
event and the physical characteristics, operating conditions, location,
and prior history of the affected pipeline in determining the
appropriate method for performing the initial inspection to determine
the extent of any damage and the need for the additional assessments
required under paragraph (a) of this section.
(c) Time period. The inspection required under paragraph (a) of
this section must commence within 72 hours after the cessation of the
event, defined as the point in time when the affected area can be
safely accessed by the personnel and equipment required to perform the
inspection as determined under paragraph (b) of this section. In the
event that the operator is unable to commence the inspection due to the
unavailability of personnel or equipment, the operator must notify the
appropriate PHMSA Region Director as soon as practicable.
(d) Remedial action. An operator must take prompt and appropriate
remedial action to ensure the safe operation of a pipeline based on the
information obtained as a result of performing the inspection required
under paragraph (a) of this section. Such actions might include, but
are not limited to:
(1) Reducing the operating pressure or shutting down the pipeline;
(2) Modifying, repairing, or replacing any damaged pipeline
facilities;
(3) Preventing, mitigating, or eliminating any unsafe conditions in
the pipeline right-of-way;
(4) Performing additional patrols, surveys, tests, or inspections;
(5) Implementing emergency response activities with Federal, State,
or local personnel; and
(6) Notifying affected communities of the steps that can be taken
to ensure public safety.

0
12. Add Sec. 195.416 to read as follows:

Sec. 195.416 Pipeline assessments.

(a) Scope. This section applies to onshore line pipe that can
accommodate inspection by means of in-line inspection tools and is not
subject to the integrity management requirements in Sec. 195.452.
(b) General. An operator must perform an initial assessment of each
of its pipeline segments by October 1, 2029, and perform periodic
assessments of its pipeline segments at least once every 10 calendar
years from the year of the prior assessment or as otherwise necessary
to ensure public safety or the protection of the environment.
(c) Method. Except as specified in paragraph (d) of this section,
an operator must perform the integrity assessment for the range of
relevant threats to the pipeline segment by the use of an appropriate
in-line inspection tool(s). When performing an assessment using an in-
line inspection tool, an operator must comply with Sec. 195.591. An
operator must explicitly consider uncertainties in reported results
(including tool tolerance, anomaly findings, and unity chart plots or
other equivalent methods for determining uncertainties) in identifying
anomalies. If this is impracticable based on operational limits,
including operating pressure, low flow, and pipeline length or
availability of in-line inspection tool technology for the pipe
diameter, then the operator must perform the assessment using the
appropriate method(s) in paragraphs (c)(1), (2), or (3) of this section
for the range of relevant threats being assessed. The methods an
operator selects to assess low-frequency electric resistance welded
pipe, pipe with a seam factor less than 1.0 as defined in Sec.
195.106(e) or lap-welded pipe susceptible to longitudinal seam failure
must be capable of assessing seam integrity, cracking, and of detecting
corrosion and deformation anomalies. The following alternative
assessment methods may be used as specified in this paragraph:
(1) A pressure test conducted in accordance with subpart E of this
part;

[[Page 52296]]

(2) External corrosion direct assessment in accordance with Sec.
195.588; or
(3) Other technology in accordance with paragraph (d).
(d) Other technology. Operators may elect to use other technologies
if the operator can demonstrate the technology can provide an
equivalent understanding of the condition of the line pipe for threat
being assessed. An operator choosing this option must notify the Office
of Pipeline Safety (OPS) 90 days before conducting the assessment by:
(1) Sending the notification, along with the information required
to demonstrate compliance with this paragraph, to the Information
Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous
Materials Safety Administration, 1200 New Jersey Avenue SE, Washington,
DC 20590; or
(2) Sending the notification, along with the information required
to demonstrate compliance with this paragraph, to the Information
Resources Manager by facsimile to (202) 366-7128.
(3) Prior to conducting the ``other technology'' assessments, the
operator must receive a notice of ``no objection'' from the PHMSA
Information Services Manager or Designee.
(e) Data analysis. A person qualified by knowledge, training, and
experience must analyze the data obtained from an assessment performed
under paragraph (b) of this section to determine if a condition could
adversely affect the safe operation of the pipeline. Operators must
consider uncertainties in any reported results (including tool
tolerance) as part of that analysis.
(f) Discovery of condition. For purposes of Sec. 195.401(b)(1),
discovery of a condition occurs when an operator has adequate
information to determine that a condition presenting a potential threat
to the integrity of the pipeline exists. An operator must promptly, but
no later than 180 days after an assessment, obtain sufficient
information about a condition to make that determination required under
paragraph (e) of this section, unless the operator can demonstrate the
180-day interval is impracticable. If the operator believes that 180
days are impracticable to make a determination about a condition found
during an assessment, the pipeline operator must notify PHMSA and
provide an expected date when adequate information will become
available. This notification must be made in accordance with Sec.
195.452 (m).
(g) Remediation. An operator must comply with the requirements in
Sec. 195.401 if a condition that could adversely affect the safe
operation of a pipeline is discovered in complying with paragraphs (e)
and (f) of this section.
(h) Consideration of information. An operator must consider all
relevant information about a pipeline in complying with the
requirements in paragraphs (a) through (g) of this section.

0
13. Revise Sec. 195.444 to read as follows:

Sec. 195.444 Leak detection.

(a) Scope. Except for offshore gathering and regulated rural
gathering pipelines, this section applies to all hazardous liquid
pipelines transporting liquid in single phase (without gas in the
liquid).
(b) General. A pipeline must have an effective system for detecting
leaks in accordance with Sec. Sec. 195.134 or 195.452, as appropriate.
An operator must evaluate the capability of its leak detection system
to protect the public, property, and the environment and modify it as
necessary to do so. At a minimum, an operator's evaluation must
consider the following factors--length and size of the pipeline, type
of product carried, the swiftness of leak detection, location of
nearest response personnel, and leak history.
(c) CPM leak detection systems. Each computational pipeline
monitoring (CPM) leak detection system installed on a hazardous liquid
pipeline must comply with API RP 1130 (incorporated by reference, see
Sec. 195.3) in operating, maintaining, testing, record keeping, and
dispatcher training of the system.

0
14. Amend Sec. 195.452 by:
0
a. Revising paragraphs (a)(3) and (b)(1), the introductory text of
paragraph (c)(1)(i), paragraphs (c)(1)(i)(A), (d), (e)(1)(vii), and
(g), the introductory text of paragraph (h)(1), and paragraph (h)(2);
0
b. Amending paragraph (i)(2)(viii) by removing the period at the end of
the sentence and adding in its place a ``;''.
0
c. Adding paragraph (i)(2)(ix);
0
d. Revising paragraph (j)(2);
0
e. Adding paragraphs (n) and (o).
The revisions and additions read as follows:

Sec. 195.452 Pipeline integrity management in high consequence areas.

(a) * * *
(3) Category 3 includes pipelines constructed or converted after
May 29, 2001, and low-stress pipelines in rural areas under Sec.
195.12.
* * * * *
(b) * * *
(1) Develop a written integrity management program that addresses
the risks on each segment of pipeline in the first column of the
following table no later than the date in the second column:

------------------------------------------------------------------------
Pipeline Date
------------------------------------------------------------------------
Category 1................................ March 31, 2002.
Category 2................................ February 18, 2003.
Category 3................................ Date the pipeline begins
operation or as provided in
Sec. 195.12 for low
stress pipelines in rural
areas.
------------------------------------------------------------------------

* * * * *
(c) * * *
(1) * * *
(i) The methods selected to assess the integrity of the line pipe.
An operator must assess the integrity of the line pipe by in-line
inspection tool(s) described in paragraph (c)(1)(i)(A) of this section
for the range of relevant threats to the pipeline segment. If it is
impracticable based upon the construction of the pipeline (e.g.,
diameter changes, sharp bends, and elbows) or operational limits
including operating pressure, low flow, pipeline length, or
availability of in-line inspection tool technology for the pipe
diameter, then the operator must use the appropriate method(s) in
paragraphs (c)(1)(i)(B), (C), or (D) of this section for the range of
relevant threats to the pipeline segment. The methods an operator
selects to assess low-frequency electric resistance welded pipe, pipe
with a seam factor less than 1.0 as defined in Sec. 195.106(e) or lap-
welded pipe susceptible to longitudinal seam failure, must be capable
of assessing seam integrity, cracking, and of detecting corrosion and
deformation anomalies.
(A) In-line inspection tool or tools capable of detecting corrosion
and deformation anomalies including dents, gouges, and grooves. For
pipeline segments with an identified or probable risk or threat related
to cracks (such as at pipe body or weld seams) based on the risk
factors specified in paragraph (e), an operator must use an in-line
inspection tool or tools capable of detecting crack anomalies. When
performing an assessment using an in-line inspection tool, an operator
must comply with Sec. 195.591. An operator using this method must
explicitly consider uncertainties in reported results (including tool
tolerance, anomaly findings, and unity chart plots or equivalent for
determining uncertainties) in identifying anomalies;
* * * * *
(d) When must operators complete baseline assessments?
(1) All pipelines. An operator must complete the baseline
assessment before a new or conversion-to-service pipeline

[[Page 52297]]

begins operation through the development of procedures, identification
of high consequence areas, and pressure testing of could-affect high
consequence areas in accordance with Sec. 195.304.
(2) Newly identified areas. If an operator obtains information
(whether from the information analysis required under paragraph (g) of
this section, Census Bureau maps, or any other source) demonstrating
that the area around a pipeline segment has changed to meet the
definition of a high consequence area (see Sec. 195.450), that area
must be incorporated into the operator's baseline assessment plan
within 1 year from the date that the information is obtained. An
operator must complete the baseline assessment of any pipeline segment
that could affect a newly identified high consequence area within 5
years from the date an operator identifies the area.
* * * * *
(e) * * *
(1) * * *
(vii) Local environmental factors that could affect the pipeline
(e.g., seismicity, corrosivity of soil, subsidence, climatic);
* * * * *
(g) What is an information analysis? In periodically evaluating the
integrity of each pipeline segment (see paragraph (j) of this section),
an operator must analyze all available information about the integrity
of its entire pipeline and the consequences of a possible failure along
the pipeline. Operators must continue to comply with the data
integration elements specified in Sec. 195.452(g) that were in effect
on October 1, 2018, until October 1, 2022. Operators must begin to
integrate all the data elements specified in this section starting
October 1, 2020, with all attributes integrated by October 1, 2022.
This analysis must:
(1) Integrate information and attributes about the pipeline that
include, but are not limited to:
(i) Pipe diameter, wall thickness, grade, and seam type;
(ii) Pipe coating, including girth weld coating;
(iii) Maximum operating pressure (MOP) and temperature;
(iv) Endpoints of segments that could affect high consequence areas
(HCAs);
(v) Hydrostatic test pressure including any test failures or
leaks--if known;
(vi) Location of casings and if shorted;
(vii) Any in-service ruptures or leaks--including identified
causes;
(viii) Data gathered through integrity assessments required under
this section;
(ix) Close interval survey (CIS) survey results;
(x) Depth of cover surveys;
(xi) Corrosion protection (CP) rectifier readings;
(xii) CP test point survey readings and locations;
(xiii) AC/DC and foreign structure interference surveys;
(xiv) Pipe coating surveys and cathodic protection surveys.
(xv) Results of examinations of exposed portions of buried
pipelines (i.e., pipe and pipe coating condition, see Sec. 195.569);
(xvi) Stress corrosion cracking (SCC) and other cracking (pipe body
or weld) excavations and findings, including in-situ non-destructive
examinations and analysis results for failure stress pressures and
cyclic fatigue crack growth analysis to estimate the remaining life of
the pipeline;
(xvii) Aerial photography;
(xviii) Location of foreign line crossings;
(xix) Pipe exposures resulting from repairs and encroachments;
(xx) Seismicity of the area; and
(xxi) Other pertinent information derived from operations and
maintenance activities and any additional tests, inspections, surveys,
patrols, or monitoring required under this part.
(2) Consider information critical to determining the potential for,
and preventing, damage due to excavation, including current and planned
damage prevention activities, and development or planned development
along the pipeline;
(3) Consider how a potential failure would affect high consequence
areas, such as location of a water intake.
(4) Identify spatial relationships among anomalous information
(e.g., corrosion coincident with foreign line crossings; evidence of
pipeline damage where aerial photography shows evidence of
encroachment). Storing the information in a geographic information
system (GIS), alone, is not sufficient. An operator must analyze for
interrelationships among the data.
(h) * * *
(1) General requirements. An operator must take prompt action to
address all anomalous conditions in the pipeline that the operator
discovers through the integrity assessment or information analysis. In
addressing all conditions, an operator must evaluate all anomalous
conditions and remediate those that could reduce a pipeline's
integrity, as required by this part. An operator must be able to
demonstrate that the remediation of the condition will ensure that the
condition is unlikely to pose a threat to the long-term integrity of
the pipeline. An operator must comply with all other applicable
requirements in this part in remediating a condition. Each operator
must, in repairing its pipeline systems, ensure that the repairs are
made in a safe and timely manner and are made so as to prevent damage
to persons, property, or the environment. The calculation method(s)
used for anomaly evaluation must be applicable for the range of
relevant threats.
* * * * *
(2) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information to determine that a condition
presenting a potential threat to the integrity of the pipeline exists.
An operator must promptly, but no later than 180 days after an
assessment, obtain sufficient information about a condition to make
that determination, unless the operator can demonstrate the 180-day
interval is impracticable. If the operator believes that 180 days are
impracticable to make a determination about a condition found during an
assessment, the pipeline operator must notify PHMSA in accordance with
paragraph (m) of this section and provide an expected date when
adequate information will become available.
* * * * *
(i) * * *
(2) * * *
(ix) Seismicity of the area.
* * * * *
(j) * * *
(2) Verifying covered segments. An operator must verify the risk
factors used in identifying pipeline segments that could affect a high
consequence area on at least an annual basis not to exceed 15 months
(Appendix C of this part provides additional guidance on factors that
can influence whether a pipeline segment could affect a high
consequence area). If a change in circumstance indicates that the prior
consideration of a risk factor is no longer valid or that an operator
should consider new risk factors, an operator must perform a new
integrity analysis and evaluation to establish the endpoints of any
previously identified covered segments. The integrity analysis and
evaluation must include consideration of the results of any baseline
and periodic integrity assessments (see paragraphs (b), (c), (d), and
(e) of this section), information analyses (see paragraph (g) of this
section), and decisions about remediation and preventive and mitigative
actions (see paragraphs (h) and (i) of this section). An operator must
complete the first annual verification

[[Page 52298]]

under this paragraph no later than July 1, 2021.
* * * * *
(n) Accommodation of instrumented internal inspection devices--
(1) Scope. This paragraph does not apply to any pipeline facilities
listed in Sec. 195.120(b).
(2) General. An operator must ensure that each pipeline is modified
to accommodate the passage of an instrumented internal inspection
device by July 2, 2040.
(3) Newly identified areas. If a pipeline could affect a newly
identified high consequence area (see paragraph (d)(2) of this section)
after July 2, 2035, an operator must modify the pipeline to accommodate
the passage of an instrumented internal inspection device within 5
years of the date of identification or before performing the baseline
assessment, whichever is sooner.
(4) Lack of accommodation. An operator may file a petition under
Sec. 190.9 of this chapter for a finding that the basic construction
(i.e., length, diameter, operating pressure, or location) of a pipeline
cannot be modified to accommodate the passage of an instrumented
internal inspection device or that the operator determines it would
abandon or shut-down a pipeline as a result of the cost to comply with
the requirement of this section.
(5) Emergencies. An operator may file a petition under Sec. 190.9
of this chapter for a finding that a pipeline cannot be modified to
accommodate the passage of an instrumented internal inspection device
as a result of an emergency. An operator must file such a petition
within 30 days after discovering the emergency. If the petition is
denied, the operator must modify the pipeline to allow the passage of
an instrumented internal inspection device within 1 year after the date
of the notice of the denial.

0
15. Add Sec. 195.454 to Subpart F to read as follows:

Sec. 195.454 Integrity assessments for certain underwater hazardous
liquid pipeline facilities located in high consequence areas.

Notwithstanding any pipeline integrity management program or
integrity assessment schedule otherwise required under Sec. 195.452,
each operator of any underwater hazardous liquid pipeline facility
located in a high consequence area that is not an offshore pipeline
facility and any portion of which is located at depths greater than 150
feet under the surface of the water must ensure that:
(a) Pipeline integrity assessments using internal inspection
technology appropriate for the integrity threats to the pipeline are
completed not less often than once every 12 months, and;
(b) Pipeline integrity assessments using pipeline route surveys,
depth of cover surveys, pressure tests, external corrosion direct
assessment, or other technology that the operator demonstrates can
further the understanding of the condition of the pipeline facility,
are completed on a schedule based on the risk that the pipeline
facility poses to the high consequence area in which the pipeline
facility is located.

Issued in Washington, DC, on September 17, 2019, under authority
delegated in 49 CFR part 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2019-20458 Filed 9-30-19; 8:45 am]
BILLING CODE 4910-60-P

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