Pipeline Safety: Safety of Hazardous Liquid Pipelines, 61609-61643 [2015-25359]

Download as PDF Vol. 80 Tuesday, No. 197 October 13, 2015 Part III Department of Transportation asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Pipeline and Hazardous Materials Safety Administration 49 CFR Part 195 Pipeline Safety: Safety of Hazardous Liquid Pipelines; Proposed Rule VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\13OCP3.SGM 13OCP3 61610 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 195 [Docket No. PHMSA–2010–0229] RIN 2137–AE66 Pipeline Safety: Safety of Hazardous Liquid Pipelines Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Notice of proposed rulemaking. AGENCY: In recent years, there have been significant hazardous liquid pipeline accidents, most notably the 2010 crude oil spill near Marshall, Michigan, during which almost one million gallons of crude oil were spilled into the Kalamazoo River. In response to accident investigation findings, incident report data and trends, and stakeholder input, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) in the Federal Register on October 18, 2010. The ANPRM solicited stakeholder and public input and comments on several aspects of hazardous liquid pipeline regulations being considered for revision or updating in order to address the lessons learned from the Marshall, Michigan accident and other pipeline safety issues. Subsequently, Congress enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act that included several provisions that are relevant to the regulation of hazardous liquid pipelines. Shortly after the Pipeline Safety, Regulatory Certainty, and Job Creation Act was passed, the National Transportation Safety Board (NTSB) issued its accident investigation report on the Marshall, Michigan accident. In it, NTSB made additional recommendations regarding the need to revise and update hazardous liquid pipeline regulations. In response to these mandates, recommendations, lessons learned, and public input, PHMSA is proposing to make changes to the hazardous liquid pipeline safety regulations. PHMSA is proposing these changes 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 unsafe conditions, and mitigating the adverse effects of pipeline failures. DATES: Persons interested in submitting written comments on this NPRM must asabaliauskas on DSK5VPTVN1PROD with PROPOSALS SUMMARY: VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 do so by January 8, 2016. PHMSA will consider late filed comments so far as practicable. ADDRESSES: You may submit comments identified by the docket number PHMSA–2010–0229 by any of the following methods: Federal eRulemaking Portal: https:// www.regulations.gov. Follow the online instructions for submitting comments. Fax: 1–202–493–2251. Mail: Hand Delivery: U.S. DOT Docket Management System, West Building Ground Floor, Room W12–140, 1200 New Jersey Avenue SE., Washington, DC 20590–0001, between 9 a.m. and 5 p.m., Monday through Friday, except federal holidays. Instructions: If you submit your comments by mail, submit two copies. To receive confirmation that PHMSA received your comments, include a selfaddressed stamped postcard. Note: Comments are posted without changes or edits to https:// www.regulations.gov, including any personal information provided. There is a privacy statement published on https:// www.regulations.gov. FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202–366– 4571, by fax at 202–366–4566, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue SE., PHP–30, Washington, DC 20590–0001. SUPPLEMENTARY INFORMATION: Outline of this document: I. Executive Summary II. Background and NPRM Proposals III. Analysis of Advance Notice of Proposed Rulemaking A. Scope of Part 195 and Existing Regulatory Exceptions B. Definition of High Consequence Area C. Leak Detection Equipment and Emergency Flow Restricting Devices D. Valve Spacing E. Repair Criteria Outside of High Consequence Areas F. Stress Corrosion Cracking IV. Section by Section Analysis V. Regulatory Notices and Proposed Changes to Regulatory Text I. Executive Summary In recent years, there have been significant hazardous liquid pipeline accidents, most notably the 2010 crude oil spill near Marshall, Michigan, during which almost one million gallons of crude oil were spilled into the Kalamazoo River. In response to accident investigation findings, incident report data and trends, and stakeholder input, PHMSA published an ANPRM in the Federal Register on October 18, 2010, (75 FR 63774). The ANPRM solicited stakeholder and public input and comments on several aspects of PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 hazardous liquid pipeline regulations being considered for revision or updating in order to address the lessons learned from the Marshall, Michigan accident and other pipeline safety issues. Subsequently, Congress enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112–90) (The Act). That legislation included several provisions that are relevant to the regulation of hazardous liquid pipelines. Shortly after the Act was passed, NTSB issued its accident investigation report on the Marshall, Michigan accident. In it, NTSB made additional recommendations regarding the need to revise and update hazardous liquid pipeline regulations. Specifically, the NTSB issued recommendations P– 12–03 and P–12–04 respectively, which addressed detection of pipeline cracks and ‘‘discovery of condition’’. 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 the Pipeline and Hazardous Materials Safety Administration 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’’. In response to these mandates, recommendations, lessons learned, and public input, PHMSA is proposing to make certain changes to the Hazardous Liquid Pipeline Safety Regulations. The first and second proposals are to extend reporting requirements to all hazardous liquid gravity and gathering lines. The collection of information about these lines 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 are adequate. The third proposal is to require inspections of pipelines in areas affected by extreme weather, natural disasters, and other similar events. Such inspections will ensure that pipelines E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules are still capable of being safely operated after these events. The fourth proposal is to require periodic inline integrity assessments of hazardous liquid pipelines that are located outside of HCAs. HCA’s are already covered under the IM program requirements. These assessments will provide critical information about the condition of these pipelines, including the existence of internal and external corrosion and deformation anomalies. The fifth proposal is to require the use of leak detection systems on hazardous liquid pipelines in all locations. The use of such systems will help to mitigate the effects of hazardous liquid pipeline failures that occur outside of HCAs. The sixth proposal is to modify the provisions for making pipeline repairs. Additional conservatism will be incorporated into the existing repair criteria and an adjusted schedule will be established to provide greater uniformity. These criteria will also be made applicable to all hazardous liquid pipelines, with an extended timeframe for making repairs outside of HCAs. The seventh proposal is to require that all pipelines subject to the IM requirements be capable of accommodating inline inspection tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. Inline 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, other regulations will be clarified to improve certainty and compliance. PHMSA estimates that 421 hazardous liquid operators may incur costs to comply with the proposed rule. The estimated annual costs for the different requirements range from approximately $1,000 to $16.7 million, with aggregate costs of approximately $22.4 million. These wide ranges exist because the requirements vary widely. For example, some requirements apply only to pipelines within HCAs, some only to those outside HCAs, and some to both; other requirements apply only to onshore pipelines, and others to both on- and offshore; the length of pipeline, and the number of operators affected both vary for the different requirements. These proposals are designed to mitigate or prevent some number of hazardous liquid pipeline incidents resulting in annualized benefits estimated between approximately $3.5 and $17.7 million, depending on the requirement. Factors such as increased safety, public confidence that all pipelines are regulated, quicker discovery of leaks VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 and mitigation of environmental damages, and better risk management are considered in this analysis. The dollar value of fatalities, injuries, and property damages due to pipeline incidents are societal costs and their prevention represents potential benefits. The changes proposed in this Notice of Proposed Rulemaking (NPRM) are expected to enhance overall pipeline safety and protection of the environment. II. Background and NPRM Proposals 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). Like its predecessor, the Natural Gas Pipeline Safety Act (NGPSA) of 1968 (Pub. L. 90– 481), the HLPSA provides the Secretary of Transportation (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. Performance-based safety standards are generally favored (i.e., a particular objective is specified, but the method of achieving that objective is not). Risk management principles play a critical role in the IM requirements for HCA’s. 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. The states may submit a certification to regulate the safety standards and practices for intrastate pipelines. States certified to regulate their intrastate lines can also enter into agreements with PHMSA to serve as an agent for inspecting interstate facilities. Most state pipeline safety programs are administered by public utility commissions. These state authorities must adopt the Pipeline Safety Regulations as part of a certification or agreement, but can establish more PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 61611 stringent safety standards for those intrastate pipeline facilities that they have responsibility to regulate. PHMSA cannot regulate the safety standards or practices for an intrastate pipeline facility if a state has a current certification to regulate such facilities. Congress recently enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112–90) (The Act). That legislation included several provisions that are relevant to the regulation of hazardous liquid pipelines. As part of the rulemaking process, PHMSA presented proposed changes in response to this Act in an ANPRM published in the Federal Register on October 18, 2010, (75 FR 63774). This NPRM will, in the paragraphs that follow, describe each of the proposals PHMSA will make along with a statement of need for each and an explanation of how each of these proposals improve the pipeline safety regulations. Extend Certain Reporting Requirements to All Gravity and Rural Hazardous Liquid Gathering Lines 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 are capable of building up large amounts of pressure. 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. In order for PHMSA to effectively analyze safety performance and pipeline 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)), and that authority was not affected by any of the provisions in the Pipeline Safety Act of 2011. Accordingly, PHMSA is proposing to add 49 CFR 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. PHMSA estimates that, at most, five hazardous liquid pipeline operators will be affected. Based on comments from API–AOPL to the ANPRM, 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 proposing to extend the reporting requirements of part 195 to all hazardous liquid gathering lines. According to the legislative history, Congress originally opposed any E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS 61612 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules regulation of rural gathering lines in the Hazardous Liquid Pipeline Safety Act of 1979 (Pub. L. 96–129) for policy reasons (i.e., those lines did not present a significant risk to public safety to justify federal regulation based on the data available at that time). See S. REP. NO. 96–182 (May 15, 1979), reprinted in 1979 U.S.C.C.A.N. 1971, 1972. However, Congress eventually relaxed that prohibition in the Pipeline Safety Act of 1992 (Pub. L. 102–508) and 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 certain policy judgments in implementing those statutory provisions based on the information available at that time. 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. 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. The NTSB has also raised concerns about the safety of hazardous liquid gathering lines in the Gulf of Mexico and its inlets, which are only subject to certain inspection and reburial requirements.1 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,’’ 2 that was performed by the Oak Ridge National Laboratory and published on May 8, 2015, PHMSA is proposing additional regulations to ensure the safety of hazardous liquid gathering lines. In order for PHMSA to effectively analyze safety performance and pipeline 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)), and 1 https://app.ntsb.gov/news/2010/100624b.html. 2 https://www.phmsa.dot.gov/pv_obj_cache/pv_ obj_id_7B2B80704EBC3EBABDB5B9F701F184 E0854F3600/filename/report_to_congress_on_ gathering_lines.pdf. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 that authority was not affected by any of the provisions in the Pipeline Safety Act of 2011. Accordingly, PHMSA is proposing 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. 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 adopted a regulation in a June 2008 final rule (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 maximum operating pressure according to § 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 located in a rural area that is not unusually sensitive to environmental damage.’’) and Congress did not remove this exemption in the 2011 Act. However, the 2011 Act did require that PHMSA review whether currently unregulated gathering lines should be made subject to the same regulations as other pipelines. Require Inspections of Pipelines in Areas Affected by Extreme Weather, Natural Disasters, and Other Similar Events In July 2011 a pipeline failure occurred near Laurel, Montana, causing the release of an estimated 1,000 barrels of crude oil into the Yellowstone River. That area had experienced extensive flooding in the weeks leading up to the failure, and the operator has estimated the cleanup costs at approximately $135 million. An instance of flooding also occurred in 1994 in the State of Texas, leading to 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. As the PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 agency has noted in a series of advisory bulletins, hurricanes are 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, 2004 (70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)). These 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 is proposing 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, under this proposal an operator must inspect all potentially affected pipeline facilities post extreme weather event to 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 inspection must occur within 72 hours after the cessation of the event, or as soon as the affected area can be safely accessed by the personnel and equipment required to perform the inspection. PHMSA has found that 72 hours is reasonable and achievable in most cases. If an adverse condition is found, the operator must take appropriate remedial action to ensure the safe operation of a pipeline based on the information obtained as a result of performing the inspection. Such actions might include, but are not limited to: • Reducing the operating pressure or shutting down the pipeline; • Modifying, repairing, or replacing any damaged pipeline facilities; • Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-ways (ROWS); • Performing additional patrols, surveys, tests, or inspections; • 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 proposal is based on the experience of PHMSA and is expected to increase the likelihood that safety E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules conditions will be found earlier and responded to more quickly. PHMSA invites comment on this and other proposals in this NPRM. In regard to this proposal, PHMSA has particular interest in additional comments concerning how operators currently respond to these events, what type of events are encountered and if a 72 hour response time is reasonable. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Require Periodic Assessments of Pipelines That Are Not Already Covered Under the IM Program Requirements PHMSA is proposing to require 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 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 inline inspection (ILI) tool at least once every 10 years. PHMSA needs operators to complete assessments in HCAs followed by assessments in non-HCAs. Other assessment methods could be used if an operator provides the Office of Pipeline Safety (OPS) with prior written notice that a pipeline is not capable of accommodating an ILI tool. The written notice provided to PHMSA must include a technical demonstration of why the pipeline is not capable of accommodating an ILI tool and what alternative technology the operator proposes to use. The operator must also detail how the alternative technology would provide a substantially equivalent understanding of the pipeline’s condition in light of the threats that could affect its safe operation. Such alternative technologies would include hydrostatic pressure testing or appropriate forms of direct assessment. The individuals who review the results of these periodic assessments would need to be qualified by knowledge, training, and experience and would 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 would 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. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Operators would be 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, test, and repairs (see § 195.404), and taking appropriate remedial action under § 195.422, as discussed below. Section 195.11 would also be amended to subject regulated onshore gathering lines to the periodic assessment requirement. PHMSA believes by proposing the above amendment to the existing pipeline safety regulations, safety will be increased for all pipelines both in and out of HCAs. Such a requirement would ensure operators obtain information necessary for prompt detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Currently, operators have indicated that they are performing ILI assessments on a large majority of their pipelines even though no regulation requires them to do so outside of HCAs. PHMSA wants to ensure that current assessment rates continue and expand to those areas not voluntarily assessed. Of the many methods to assess, PHMSA has found that ILI in many cases is the most efficient and effective. PHMSA considered alternatives to its proposal that would likely have lower overall costs and benefits, but potentially higher net benefits. For instance, PHMSA considered limiting the proposed expansion of certain IM requirements to those pipelines where a spill could affect a building or occupied site such as a playground, or highway. Under this alternative, pipelines in a location where a spill could not affect a building, occupied site, or highway would not be subject to these new requirements. However, this alternative would offer less protection to the natural environment, including sensitive and protected habitats and species. PHMSA also considered alternative assessment intervals to the proposed 10 year interval, such as a 15or 20-year interval. However, substantial changes to pipeline integrity can occur in a short timeframe. PHMSA declined to propose these alternatives because they would provide fewer benefits than the proposed approach. More specifically, liquid spills, even in remote areas, can result in environmental damage necessitating clean up and incurring restoration costs PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 61613 and lost use and nonuse values. If pipe is not assessed and repaired in accordance with this proposal, liquid spills are likely to occur. Also, a longer interval between assessments would increase risks of integrity-related failure compared to PHMSA’s proposal. PHMSA was unable to quantify the benefits and costs of these alternatives due to limitations in available information, such as the amount of unassessed pipe where a spill could not affect a building, occupied site, or highway; the environmental impact of spills from such pipe; and the incremental reduction in benefit between 10-year and alternative interval periods. PHMSA seeks public comments on these alternatives, and the regulatory impact analysis contains specific questions for public comment on quantifying these alternatives. Modify the IM Repair Criteria and Apply Those Same Criteria to Any Pipeline Where the Operator Has Identified Repair Conditions Inspection experience indicates a weakness in current repair criteria. Specifically, the current repair criteria in non-HCAs (immediate and reasonable time) does not specify anomaly or repair time frames. It is left entirely at the operator’s discretion. Therefore, PHMSA is proposing to modify the IM pipeline repair criteria and to apply the criteria to non-IM pipeline repairs. Specifically, the criteria in § 195.452(h) for IM repairs would be modified to: • Categorize bottom-side dents with stress risers as immediate repair conditions; • Require immediate repairs whenever the calculated burst pressure is less than 1.1 times maximum operating pressure; • Eliminate the 60-day and 180-day repair categories; and • Establish a new, consolidated 270day repair category. PHMSA is also proposing 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. PHMSA believes that these changes will ensure that immediate action is taken to remediate anomalies that present an imminent threat to the integrity of hazardous liquid pipelines in all locations. Moreover, many anomalies that would not qualify as immediate repairs under the current criteria will meet that requirement as a result of the additional conservatism E:\FR\FM\13OCP3.SGM 13OCP3 61614 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules that will be incorporated into the burst pressure calculations. The new time frames for performing non-immediate repairs will also allow operators to remediate those conditions in a timely manner while allocating resources to those areas that present a higher risk of harm to the public, property, and the environment. The existing requirements in § 195.422 would also be modified to include a general requirement for performing all other repairs within a reasonable time. A proposed amendment to § 195.11 would extend these new pipeline remediation requirements to regulated onshore gathering lines. As a result of these changes, PHMSA would modify the existing general requirements for pipeline repairs in § 195.401(b). Paragraph (b)(1) would be modified to reference the new timeframes in § 195.422(d) and (e) for remediating conditions that could adversely affect the safe operation of a pipeline segment not subject to the IM requirements in § 195.452. The requirements in paragraph (b)(2) for IM repairs under § 195.452(h) will be retained without change. A new paragraph (b)(3) will be added, however, to 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, including those covered by the timeframes specified in §§ 195.422(d) and (e) and 195.452(h). asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Expand the Use of Leak Detection Systems for All Hazardous Liquid Pipelines PHMSA is proposing to amend § 195.134 to require that all new hazardous liquid pipelines be designed to include leak detection systems. Recent pipeline accidents, including a pair of related failures that occurred in 2010 on a crude oil pipeline in Salt Lake City, Utah, corroborate the significance of having an adequate means for identifying leaks in all locations. PHMSA, aware of the significance of leak detection, held two recent workshops in Rockville, Maryland on March 27–28 of 2012. 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. Currently, part 195 contains mandatory leak detection requirements for hazardous liquid pipelines that could affect an HCA. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Congress included additional requirements for leak detection systems in section 8 of the Pipeline Safety Act of 2011. 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 consequence of establishing additional standards for the use of those systems. To provide Congress with an opportunity to review that report, the Secretary is prohibited from issuing any final leak detection regulations for a specified time period (i.e., 2 years from the date of the enactment of the Pipeline Safety Act of 2011, or 1-year after the submission of the leak detection report to Congress, whichever is earlier), unless a condition exists that poses a risk to public safety, property, or the environment, or is an imminent hazard, and the issuance of such regulations would address that risk or hazard. Other provisions in part 195 help to detect and mitigate the effects of pipeline leaks, including the Right of Way (ROW). In addition to modifying § 195.444 to require a means for detecting leaks on all portions of a hazardous liquid pipeline system, PHMSA is proposing that operators be required to have an evaluation performed to determine what kinds of systems must be installed to adequately protect the public, property, and the environment. The factors that must be considered in performing that evaluation would include the characteristics and history of the affected pipeline, the capabilities of the available leak detection systems, and the location of emergency response personnel. A proposed amendment to § 195.11 would extend these new leak detection requirements to regulated onshore gathering lines. PHMSA is retaining and is not proposing any modification to the requirement in §§ 195.134 and 195.444 that each new computational leak detection system comply with the applicable requirements in the API RP 1130 standard. PHMSA does not propose to make any additional changes to the regulations concerning specific leak detection requirements at this time. PHMSA will be studying this issue further and may make proposals concerning this topic in a later rulemaking. PHMSA recently publicly provided the results of the 2012 Keifner and Associates study of leak detection systems in the pipeline industry, including the current state of technology. PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 Increase the Use of Inline Inspection Tools PHMSA is proposing to require that all hazardous liquid pipelines in HCA’s 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 are designed to accommodate inline inspection tools. The basis for these requirements was a 1988 law that addressed the Secretary’s authority with regard to requiring the accommodation 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). 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). As the Research and Special Programs Administration (RSPA), (a predecessor agency of PHMSA) explained in the final rule April 12, 1994 (59 FR 17275) that promulgated § 195.120, ‘‘[t]he 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.’’ April 2, 1994, (59 FR 17279). 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 April 2, 1994, (59 FR 17275). RSPA established requirements for the use of ILI tools in pipelines that could affect HCAs in the December 2000 IM final rule 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. E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules 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. PHMSA is proposing to use the authority provided in section 60102(f)(1)(B) to further facilitate the ‘‘gradual elimination’’ of pipelines that are not capable of accommodating smart pigs. PHMSA would limit 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, and other unforeseen construction problems. PHMSA believes that an exception should still be available for emergencies and where the basic construction of a pipeline makes that accommodation impracticable, but that the other, less urgent circumstances listed in the regulation are no longer appropriate. Accordingly, the allowances for construction-related time constraints and problems would be repealed. Modern ILI tools are capable of providing a relatively complete examination of the entire length of a pipeline, including information about threats that cannot always be identified using other assessment methods. 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. Similarly, external corrosion direct assessment (ECDA) can identify instances where coating damage may be affecting pipeline integrity, but additional activities, including followup excavations and direct examinations, must be performed to verify the extent of that threat. ECDA also provides less information about the internal condition of a pipe than ILI tools. As with new pipelines, operators will be allowed to petition the PHMSA Administrator for a finding that the basic construction, (i.e., terrain or location, of a pipeline or an emergency) VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 will not permit the accommodation of a smart pig. Clarify Other Requirements PHMSA is also proposing 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 correct an inconsistency in 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 one-year after the pipeline begins operation. These provisions are inconsistent as the identification could affect segments, and performance of baseline assessments are elements of the written IM program. PHMSA would amend the table in (b)(1) to resolve this inconsistency by eliminating the oneyear 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. A decade’s worth of IM inspection experience has shown that many operators are performing inadequate information analyses (e.g., they are collecting information, but not affording it sufficient consideration). Integration is one of the most important aspects of the IM program because it is used in identifying interactions between threats or conditions affecting the pipeline and in setting priorities for dealing with identified issues. For example, evidence of potential corrosion in an area with foreign line crossings and recent aerial patrol indications of excavation activity could indicate a priority need for further investigation. Consideration of each of these factors individually would not reveal any need for priority attention. PHMSA is concerned that a major benefit to pipeline safety intended in the initial rule is not being realized because of inadequate information analyses. For this reason, PHMSA is proposing to add additional specificity to paragraph (g) by establishing a number of pipeline attributes that must be included in these analyses and to require explicitly that operators integrate analyzed information. PHMSA is also proposing that operators consider explicitly any spatial relationships among anomalous information. PHMSA PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 61615 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 proposing that operators verify their segment identification 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. PHMSA believes that operators should periodically re-visit their initial analyses to determine whether they need to be updated. New HCAs may be identified. Construction activities or erosion near the pipeline could change local topography in a way that could cause product released in an accident to travel further 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 larger area being affected by a potential release if the original segment identification relied on emergency response to limit the transport of released product. The change that PHMSA is proposing would not require that operators reperform 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 identification. If so, the operator would be required to perform a new analysis to validate or change the endpoints of the segments affected by the change. Third, PHMSA is proposing to clarify, through the use of an explicit reference that the IM requirements apply to portions of ‘‘pipelines’’ 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. Through IM inspections, E:\FR\FM\13OCP3.SGM 13OCP3 61616 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules PHMSA has learned 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 Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 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 is proposing 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. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS III. Analysis of Advance Notice of Proposed Rulemaking On October 18, 2010, (75 FR 63774), PHMSA published an ANPRM asking the public to comment on several proposed changes to part 195. The ANPRM sought comments on: • Scope of part 195 and existing regulatory exceptions; • Criteria for designation of HCAs; • Leak detection and emergency flow restricting devices; • Valve spacing; • Repair criteria outside of HCAs; and • Stress corrosion cracking. The ANPRM may be viewed at https:// www.regulations.gov by searching for Docket ID PHMSA–2010–0229. Twenty-one organizations and individuals submitted comments in response to the ANPRM. The individual docket item numbers are listed for each comment. • Associations representing pipeline operators (trade associations) Æ American Petroleum Institute— Association of Oil Pipelines (API– AOPL) (PHMSA–2010–0229–0030) Æ Independent Petroleum Association of America (IPAA) (PHMSA–2010– 0229–0024) Æ Canadian Energy Pipeline Association (CEPA) (PHMSA–2010– 0229–0008) Æ Oklahoma Independent Petroleum Association (OIPA) (PHMSA–2010– 0229–0018) Æ Texas Pipeline Association (TPA) (PHMSA–2010–0229–0011) VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Æ Louisiana Midcontinent Oil & Gas Association (LMOGA) (PHMSA– 2010–0229–0018) Æ Texas Oil & Gas Association (TxOGA) (PHMSA–2010–0229– 0022) • Transmission and Distribution Pipeline Companies Æ TransCanada Keystone (PHMSA– 2010–0229–0027) • Government/Municipalities Æ Defense Logistics Agency (DLA) (PHMSA–2010–0229–0016) Æ Metro Area Water Utility Commission (MAWUC) (PHMSA– 2010–0229–0031) Æ North Slope Borough (NSB) (PHMSA–2010–0229–0012) • Pipeline Safety Regulators Æ National Association of Pipeline Safety Representatives (NAPSR) (PHMSA–2010–0229–0032) • Citizens’ Groups Æ Pipeline Safety Trust (PST) (PHMSA–2010–0229–0014) Æ Cook Inlet Regional Citizens Advisory Council (CRAC)) (PHMSA–2010–0229–0019) Æ The Wilderness Society (TWS) (PHMSA–2010–0229–0025) Æ National Resources Defense Council et al. (NRDC) (PHMSA– 2010–0229–0021) Æ Alaska Wilderness League et al. (AKW) (PHMSA–2010–0229–0026) • Citizens Æ Patrick Coyle (PHMSA–2010–0229– 0002) Æ Marian J. Stec (PHMSA–2010– 0229–0007) Æ Pamela A. Miller (PHMSA–2010– 0229–0013) Æ Anonymous (PHMSA–2010–0229– 0005) (The anonymous comment dealt with quality of drinking water and release permits under the Clean Water Act. These topics are beyond the scope of PHMSA’s jurisdiction and are not discussed further). Comments are reviewed in the order the ANPRM presented questions for comment. PHMSA responses to the comments follow. A. Scope of Part 195 and Existing Regulatory Exceptions Comments API–AOPL, LMOGA, TxOGA, and TransCanada Keystone expressed support for the gravity line exception. These commenters stated that gravity lines are short, pose little risk, and are usually located within other regulated facilities, such as tank farms. NAPSR did not support a complete repeal of this exception, suggesting there was no data to support such an action. NAPSR PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 did suggest that the exception should not apply to ethanol pipelines, which are very susceptible to internal corrosion. MAWUC indicated that gravity lines in HCAs should be regulated because of the sensitivity of these areas. MAWUC further stated that these lines (and other rural onshore gathering lines) contain contaminants that are not present in products carried by other pipelines, that these contaminants are dangerous to pipeline workers, and that the impact of releases from these pipelines on the environment is the same as releases from regulated pipelines. Response PHMSA does not, at this time, intend to repeal the exemption for gravity lines, but does propose to extend reporting requirements to all hazardous liquid gravity lines. The collection of information about these lines 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 are adequate. Rural Gathering Lines Comments PHMSA received a number of comments on whether to modify or repeal the requirements in § 195.1(a)(4). API–AOPL, LMOG, IPAA, OIPA, and TxOGA stated that the regulatory exception for rural gathering lines is appropriate and should not be repealed or modified. They indicated that these lines are the source of a small percentage of spills, and that gathering lines in populated areas and near navigable waterways are already subject to PHMSA regulation. Among citizens’ groups, TWS suggested that PHMSA should examine federal and state release data from all excepted pipelines and regulate those with release rates similar to currently regulated pipelines. PST supported expansion of the definition of gathering line to the extent statutorily possible to capture all lines. Similarly, CRAC, TWS, and AKW indicated the exception should be removed and regulation expanded to include produced water lines and production lines. TWS and AKW also stated that flow lines, which are currently defined by regulation as production facilities, should be reclassified and regulated as gathering lines. The government/municipalities NSB and MAWUC also commented concerning the rural gathering line exception. NSB requested PHMSA place a high priority on removing the E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules exception for gathering lines. MAWUC supported no gathering line exceptions in HCAs. Citizen Miller commented that PHMSA should regulate production and produced water lines on Alaska’s North Slope, because this area is very sensitive and includes pristine wetlands and fish and wildlife habitats of national and international importance. She further commented that river and coastline pipeline routes and crossings in the Arctic and subarctic Alaska are particularly of concern due to the rapid change in permafrost, as well as high rates of coastal erosion which greatly increases the environmental and human impacts of spills. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Response PHMSA believes that the requirements of the Pipeline Safety Act of 2011 and concerns for adequate regulatory oversight can only be addressed if PHMSA obtains additional information about gathering lines. PHMSA has the statutory authority to gather data for all gathering lines (49 U.S.C. 60117(b)), and that authority was not affected by any of the provisions in the Pipeline Safety Act of 2011. Accordingly, PHMSA is proposing to amend 49 CFR 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. Carbon Dioxide Lines In the ANPRM, PHMSA asked whether the agency should repeal or modify the regulatory exception for carbon dioxide pipelines used in the well injection and recovery production process. Section 195.1(b)(10) states that part 195 does not apply to the transportation of carbon dioxide downstream from the applicable following point: (i) The inlet of a compressor used in the injection of carbon dioxide for oil recovery operations, or the point where recycled carbon dioxide enters the injection system, whichever is farther upstream; or (ii) The connection of the first branch pipeline in the production field where the pipeline transports carbon dioxide to an injection well or to a header or manifold from which a pipeline branches to an injection well. Comments The trade associations, LMOGA, API– AOPL, OIPA, TxOGA, and IPAA, commented that PHMSA should not repeal the exception for carbon dioxide lines used in the well injection and VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 recovery production process. They indicated the potential risk from a production facility carbon dioxide pipeline failure is low due to factors of low potential release volumes, rapid dispersion, and low potential for human exposure. NAPSR suggested the current exception is appropriate and noted that there is no data indicating the need for a repeal. Response The regulatory history shows that the exception in § 195.1(b)(10) is limited in scope and only applies to carbon dioxide pipelines that are directly used in the production of hazardous liquids. See June 12, 1994, (56 FR 26923) (stating in preamble to 1991 final rule that ‘‘the exception is limited to lines downstream of where carbon dioxide is delivered to a production facility in the vicinity of a well site, rather than excepting all the CO2 lines in the broad expanses of a production field.’’); January 21, 1994, (59 FR 3390) (stating in preamble to June 1994 that agency adopted amendment ‘‘to clarify that the exception covers pipelines used in the injection of carbon dioxide for oil recovery operations.’’). Congress has indicated that such facilities should not be subject to federal regulation, and none of the commenters supported a repeal or modification of this exception. Accordingly, PHMSA is not proposing to repeal or modify § 195.1(b)(10). Offshore Lines in State Waters In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for offshore pipelines in state waters. Comments TransCanada Keystone, an industry commenter, and the trade associations, API–AOPL, LMOGA and TxOGA, stated the current exception should not be changed. API–AOPL pointed out that PHMSA’s jurisdiction lies only with the transportation of hazardous liquids, not hydrocarbon production areas of offshore operations. API–AOPL further stated that changing the state waters exception would unnecessarily add a duplicative layer of federal regulation. The citizens’ groups, TWS and AKW, supported removal of this exemption and increased enforcement in state waters. Likewise, among the government/municipality comments, NSB indicated that the regulations need to be expanded to include lines in offshore state waters. NSB expressed concerns with lack of state enforcement, high corrosion potential, and the sensitivity of the location of the offshore PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 61617 lines, such as those in the Beaufort and Chukchi Seas. The prohibitions of the Pipeline Safety Act of 2011 do not affect PHMSA’s authority to ensure the safety of offshore gathering lines under other statutory provisions, including if such a line is hazardous to life, property, or the environment (49 U.S.C. 60112)). PHMSA also notes that the generallyapplicable limitation in section 60101(a)(22) of the Pipeline Safety Laws only applies to ‘‘onshore production . . . facilities,’’ and that the states may regulate such intrastate facilities (see e.g., Tex. Admin. Code Title. 16, sec. 8.1(a)(1)(D)). Response Congress has indicated that additional federal safety standards may be warranted for offshore gathering lines. First, we would note that this does not include offshore production pipelines. Section 195.1(b)(5) states that part 195 does not apply to the: Transportation of hazardous liquid or carbon dioxide in an offshore pipeline in state waters where the pipeline is located upstream from the outlet flange of the following farthest downstream facility; the facility where hydrocarbons or carbon dioxide are produced; or the facility where produced hydrocarbons or carbon dioxide are first separated, dehydrated, or otherwise processed. RSPA, a predecessor agency of PHMSA, adopted § 195.1(b)(5) in a June 1994 final rule June 28, 1994, (59 FR 33388). Before that time, part 195 only included an explicit exception for offshore production pipelines located on the Outer Continental Shelf. However, as explained in the preamble to the June 1994 final rule, RSPA believed that the same exception should be applied to all offshore production pipelines, including those located in state waters. Under the federal pipeline safety laws, the agency does not regulate production facilities at all. Section 21 of the Pipeline Safety Act of 2011 requires the Secretary to review the existing federal and state regulations for gathering lines and to submit a report to Congress with the results of that review. A study on these regulations, titled ‘‘Review of Existing Federal and State Regulations for Gas and Hazardous Liquid Lines,’’ was performed by the Oak Ridge National Laboratory and was published on May 8, 2015. The Secretary is also required, if appropriate, to issue regulations subjecting hazardous liquid gathering lines located offshore and in the inlets of the Gulf of Mexico to the same safety standards that apply to all other hazardous gathering lines. Section 21 E:\FR\FM\13OCP3.SGM 13OCP3 61618 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules states that any such regulations cannot be applied to production pipelines or flow lines. Congress also included a provision authorizing the collection of geospatial or technical data on transportationrelated flow lines in section 12 of the Pipeline Safety Act of 2011. A transportation-related flow line is defined for purposes of that provision as ‘‘a pipeline transporting oil off of 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.’’ Section 12 also states that nothing in that provision ‘‘authorizes the Secretary to prescribe standards for the movement of oil through production, refining, or manufacturing facilities or through oil production flow lines located on the grounds of wells.’’ Producer-Operated Pipelines on Outer Continental Shelf In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for pipelines on the OCS. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Comments TransCanada Keystone, an industry commenter, and the trade associations, API–AOPL, LMOGA, and TxOGA, stated that the current exceptions for pipelines on the OCS should remain unchanged. API–AOPL requested that PHMSA indicate what impact the Bureau of Ocean Energy Management, Regulation and Enforcement’s (BOEMRE) recent publication regarding Safety and Environmental Management Systems (SEMS) has on transportation operators. API–AOPL expressed concern that joint jurisdiction, if created by the recent BOEMRE publication, would result in regulatory uncertainty. NAPSR responded that the exceptions for pipelines on the OCS should not be changed as these lines are already regulated by the Department of Interior. Response Section 195.1(b)(6) states that part 195 does not apply to the transportation of hazardous liquid or carbon dioxide in a pipeline on the OCS where the pipeline is located upstream of the point at which operating responsibility transfers from a producting operator to a transporting operator. Section 195.1(b)(7) further provides that part 195 does not apply to a pipeline segment upstream (generally seaward) of the last valve on the last production facility on the OCS where a pipeline on the OCS is producer-operated and crosses into state waters without first connecting to a transporting operator’s VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. A producing operator of a segment falling within this exception may petition the Administrator, under § 190.9 of this chapter, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance. These exceptions are designed to ensure that a single federal agency is responsible for regulating the safety of any given pipeline segment on the OCS (i.e., the Department of Interior for producer-operated pipelines and PHMSA for transporter-operated pipelines). See final rule codifying 1976 Memorandum of Understanding (MOU) between the Departments of Transportation and Interior on the regulation of offshore pipelines in § 195.1 August 12, 1976 (41 FR 34040); direct final rule codifying 1996 MOU between the Departments of Transportation and Interior on the regulation of offshore pipelines in § 195.1 November 19, 1997 (62 FR 61692); and final rule clarifying regulation of producer-operated pipelines that cross the federal-state boundary in offshore waters without first connecting to a transportingoperator’s facility on the OCS) August 5, 2003 (68 FR 46109). None of the commenters supported the repeal or modification of § 195.1(b)(6) or (7). Accordingly, PHMSA is not proposing to take any further action with respect to these two provisions. It should also be noted that PHMSA is not responsible for administering another federal agency’s statutes or regulations. Breakout Tanks Not Used for Reinjection or Continued Transportation In the ANPRM, PHMSA asked for comment on whether the agency should expand the extent to which part 195 applies to breakout tanks. Comments PHMSA received several comments on whether the agency should expand the extent to which part 195 applies to breakout tanks. API–AOPL, supported by the industry commenter, TransCanada Keystone, and the trade associations, LMOGA and TxOGA, stated that the current definition is appropriate, and that PHMSA should review its current MOU with the Environmental Protection Agency (EPA) before making any changes to avoid duplicative regulation of these facilities. DLA, a governmental/municipal entity, echoed the comments of API–AOPL. Conversely, NAPSR stated that if PHMSA is referring to the large number PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 of small tanks that are technically under PHMSA’s authority, but currently not regulated, then this exception should be removed. Response The Pipeline Safety Laws provide PHMSA with broad authority to regulate ‘‘the storage of hazardous liquid incidental to the movement of hazardous liquid by pipeline’’ (49 U.S.C. 60101(a)(22)(A)). The term ‘‘breakout tank’’ is defined in § 195.2 to designate which aboveground tanks are regulated as breakout under part 195. See Exxon Corporation v. U.S. Department of Transportation, 978 F.Supp. 946, 949–54 (E.D. Wash. 1997). As some of the commenters noted, PHMSA has an MOU with EPA on the treatment of breakout tanks and bulk storage tanks under the requirements of the Oil Pollution Act of 1990. Such agreements can ensure the effective regulation of facilities that are subject to regulation by more than one federal agency. As in the case of offshore pipeline facilities, those agreements can also serve as a guideline on whether a tank is transportation related or nontransportation related. Accordingly, PHMSA will review its agreements with EPA to determine whether any modifications are necessary, but is not proposing to change the definition of a ‘‘breakout tank’’ in part 195 at this time. Other Exceptions or Limitations in Part 195 In the ANPRM, PHMSA asked for comment on whether the agency should repeal or modify any of the other exceptions in part 195. API–AOPL, supported by several other trade associations, including LMOGA, TxOGA, OIPA, and IPAA, commented that the exception in § 195.1(b)(8) for transportation of hazardous liquid or carbon dioxide through onshore production (including flow lines), refining, or manufacturing facilities or storage or in-plant pipeline systems associated with such facilities should not be changed. API–AOPL commented that these facilities are not within the scope of the Pipeline Safety Laws, because they are not typically operated by midstream oil and gas pipeline companies operating in the pipeline transportation system. These facilities are already covered under a 1972 MOU with EPA and do not require further duplicative regulation. Comments API–AOPL commented that the exception in § 195.1(b)(9) for piping located on the grounds of a materials E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules transportation terminal used exclusively to transfer products between nonpipeline modes of transportation should not be changed. This piping is typically isolated from pipeline pressure by devices that control pressure in the pipeline under § 195.406(b). TransCanada Keystone, an industry commenter, supported API–AOPL’s comments. The citizens’ groups NRDC and PST indicated that PHMSA should establish additional standards for diluted bitumen. Both groups suggested PHMSA establish additional regulations for that commodity due to the high temperatures and pressures at which the lines that carry it operate. Both regulatory associations, NAPSR and MAWUC, commented on other exemptions or limitations of the pipeline safety regulations. NAPSR indicated that the exemptions for pipelines under 1-mile long that serve refining, manufacturing, or terminal facilities should be eliminated for ethanol pipelines. NAPSR also requested that PHMSA verify that intrastate lines carrying other hazardous liquids, such as sulfuric acid, are regulated by the states. MAWUC indicated that there should be no regulatory exceptions in HCA segments, because these areas must be treated with the highest degree of both prevention and emergency remediation measures. Among government and municipality commenters, NSB stated that § 195.1 should be amended to include regulation of all onshore pipelines and offshore pipelines in areas of the North Slope. NSB suggests regulation should occur where the consequences of a hazardous liquid pipeline failure could adversely impact: (1) An endangered, threatened or depleted species; (2) subsistence resources and subsistence use areas; (3) a drinking water supply; (4) cultural, archeological, and historical resources; (5) navigable waterways (including waterways navigated by rural residents for the purposes of recreation, commerce, and subsistence use); (6) recreational use areas; or (7) the functioning of other regulated facilities. Regulation of all high pressure, large diameter (6-inch and greater) onshore pipelines and all offshore pipelines should start at the wellhead. One citizen commented that the river and coastline routes in the Arctic and sub-Arctic are particularly of concern because of the rapid change in permafrost, as well as high rate of coastal erosion, which greatly increase the environmental and human impacts of hazardous liquid spills. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Response Section 195.1(b)(8) states that part 195 does not apply to the transportation of hazardous liquid or carbon dioxide through onshore production (including flow lines), refining, or manufacturing facilities or storage or in-plant piping systems associated with such facilities. That exception is based on section 60101(a)(22) of the Pipeline Safety Laws, which exempts the movement of hazardous liquid through onshore production, refining, or manufacturing facilities; or storage or in-plant piping systems associated with onshore production, refining, or manufacturing facilities. Accordingly, PHMSA agrees with the commenters that the exception in § 195.1(b)(8) should not be changed. With respect to the terminal exemption in § 195.1(b)(9)(ii), it should first be noted that the term ‘‘Pipeline or pipeline system’’ is defined in § 195.2 as ‘‘all parts of a pipeline facility through which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks.’’ The term ‘‘Pipeline facility’’ is defined in § 195.2 as ‘‘new and existing pipe, rights-of-way and any equipment, facility, or building used in the transportation of hazardous liquids or carbon dioxide.’’ Under 49 U.S.C. 60101(a)(22), ‘‘transporting hazardous liquid’’ includes ‘‘the storage of hazardous liquid incidental to the movement of hazardous liquid by pipeline.’’ Section 195.1(b)(9) states that part 195 does not apply to the transportation of hazardous liquid or carbon dioxide by vessel, aircraft, tank truck, tank car, or other non-pipeline mode of transportation or through facilities located on the grounds of a materials transportation terminal if the facilities are used exclusively to transfer hazardous liquid or carbon dioxide between non-pipeline modes of transportation or between a nonpipeline mode and a pipeline. These facilities do not include any device and associated piping that are necessary to control pressure in the pipeline under § 195.406(b). One of PHMSA’s predecessors, the Materials Transportation Bureau (MTB), adopted the original version of that exception in a July 1981 final rule July 27, 1981, (46 FR 38357). In excepting the ‘‘[t]ransportation of a hazardous liquid by vessel, aircraft, tank truck, tank car, or other vehicle or terminal PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 61619 facilities used exclusively to transfer hazardous liquids between such modes of transportation,’’ MTB stated that: [Its] authority to establish minimum Federal hazardous liquid pipeline safety standards under the [Hazardous Liquid Pipeline Safety Act (HLPSA) of 1979] extends to ‘‘the movement of hazardous liquids by pipeline, or their storage incidental to such movement.’’ The Senate report that accompanied the HLPSA states that, ‘‘It is not intended that authority over storage facilities extend to storage in marine vessels or storage other than those which are incidental to pipeline transportation.’’ (Sen. Rpt. 96–182, 1st Sess., 96th Cong. (1979), p. 18.) Earlier laws had vested DOT with extensive authority to prescribe safety standards governing the movement of hazardous liquids in seagoing vessels, barges, rail cars, trucks or aircraft and storage incidental to those forms of transportation. From the words of the new HLPSA and the related Senate report language, it is clear that Congress did not want to duplicate or overlap any of those earlier laws. Thus, HLPSA regulatory authority over storage does not extend to any form of transportation other than pipeline or to any storage or terminal facilities that are used exclusively for transfer of hazardous liquids in or between any of the other forms of transportation unless that storage or terminal facility is also ‘‘incidental’’ to a pipeline which is subject to the HLPSA. These storage and terminal facilities are expressly excluded from the coverage of part 195 July 27, 1981, (46 FR 38358). RSPA modified that exception in the final rule June 28, 1994, (59 FR 33388). RSPA, however, continued to maintain the exclusion for the transportation of hazardous liquids or carbon dioxide by non-pipeline modes, and added a more detailed exclusion for transfer piping located on the grounds of a materials transportation terminal. The regulatory history demonstrates that the exception in § 195.1(b)(9) is designed to exclude piping used in transfers to non-pipeline modes of transportation and the facilities and piping at terminals that are used exclusively for such transfers. The provision is drafted to ensure that any piping that is not used exclusively to transfer product between non-pipeline modes or transportation between a nonpipeline mode and a pipeline and facilities are subject to regulation by PHMSA. None of the commenters argued in favor of changing the exception, and there is no information to suggest that such action is necessary at this time. Accordingly, PHMSA is not E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS 61620 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules proposing to modify or repeal § 195.1(b)(9). With regard to the remaining comments, section 16 of the Pipeline Safety Act of 2011 requires the Secretary to perform a comprehensive review of whether the requirements in part 195 are sufficient to ensure the safety of pipelines that transport diluted bitumen (dilbit) and to provide Congress with a report on the results of that review. That review, titled ‘‘Effects of Diluted Bitumen on Crude Oil Transmission Pipelines,’’ was performed by the National Academy of Sciences and was published in 2013. The review found there were no causes of pipeline failure unique to the transportation of diluted bitumen, or evidence of chemical or physical properties of diluted bitumen shipments that are outside the range of other crude oil shipments, or any other aspect of diluted bitumen’s transportation by pipeline that would make it more likely than other crude oils to cause releases.3 However, the safety proposals in this rulemaking address all hazardous liquid pipelines, which include pipelines that transport diluted bitumen. Multiproduct petroleum pipelines transporting ethanol blends of up to 95% are currently regulated by PHMSA under part 195 and no major ethanol spills have occurred on these pipelines. PHMSA is performing additional research into the technical issues associated with the transportation of ethanol by pipeline and will use that information to determine whether such transportation should be subject to any additional safety requirements in the future. This NPRM proposes to conform part 195 with 49 U.S.C. 60101(a)(4) making the transportation by pipeline of any biofuel that is flammable, toxic, corrosive, or would be harmful to the environment if released in significant quantities, subject to part 195. The requirements for HCA’s are addressed in another portion of this document. As noted above, PHMSA is proposing to extend the federal reporting requirements to all hazardous liquid gathering lines (whether onshore, offshore, regulated, or unregulated). In conclusion, PHMSA will not be proposing to change or eliminate any other regulatory exceptions at this time. The exception for carbon dioxide pipelines is limited in scope and only applies to production facilities. Although breakout tanks are defined in a way that limits the application of part 195, these certain storage tanks may also 3 https://phmsa.dot.gov/staticfiles/PHMSA/ DownloadableFiles/Files/Pipeline/Dilbit_1_ Transmittal_to_Congress.pdf. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 be subject to regulation by EPA. PHMSA continues to study the scope of the gathering line exemptions, but is not proposing to modify these or any other exemption. At present, nothing indicates that any of the other exceptions should be modified as part of this rulemaking proceeding, or that the issuance of regulations for underground storage facilities is necessary. Additional Safety Standards for Underground Hazardous Liquid Storage Facilities The definition of a pipeline facility in part 195 includes ‘‘any equipment, facility, or building used in the transportation of hazardous liquids . . .’’ and, as already noted above, includes storage terminals. While surface piping in storage fields located at midstream terminal facilities falls within this definition, part 195 does not contain comprehensive safety standards for the ‘‘downhole’’ underground hazardous liquid storage caverns. In addition, surface piping at storage fields located either at the production facility where a pipeline originates or a destination/consumption facility where a pipeline terminates would generally not be considered part of the transportation and, therefore, not be regulated by PHMSA in the manner that such piping located on the grounds of the midstream terminal would. RSPA provided an explanation in a July 1997 advisory bulletin June 2, 1997, (62 FR 37118) which the agency issued in response to a NTSB recommendation on the regulation of underground storage caverns (P–93–9). RSPA noted in that advisory bulletin that a recent report indicated that state regulations applied in some form to significant percentages of these facilities, and that API had developed a set of comprehensive guidelines for the underground storage of liquid hydrocarbons. As result of these state regulations, the API guidelines, and ‘‘the varying and diverse geology and hydrology of the many sites’’ RSPA stated that agency had ‘‘decided that generally applicable federal standards may not be appropriate for underground storage facilities.’’ June 2, 1997, (62 FR 37118) RSPA further stated it would be ‘‘encouraging state action and voluntary industry action as a way to assure underground storage safety instead of proposing additional federal regulations.’’ Id. PHMSA understands that Court decisions preempting state from regulating interstate facilities appears to be a concern for state regulators. PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 Comments PHMSA requested comment on the promulgation of new or additional safety standards for underground hazardous liquid storage. The industry commenter, TransCanada Keystone, supported the comments of API–AOPL, as did the trade associations LMOGA and TxOGA. API–AOPL stated that the current exclusion of the underground cavern is appropriate as they are already regulated by the states. API–AOPL indicated that the states are better suited to regulate these facilities because of their knowledge of these facilities and locations. One government/municipality, DLA, commented that there was no need for new regulations for underground hazardous liquid storage facilities. DLA maintains that these facilities are currently regulated for purposes of the Clean Air Act under both 40 CFR parts 112 and 280 by the EPA. Response None of the commenters supported the issuance of additional regulations for underground hazardous liquid storage caverns, and there is no information suggesting that such action is necessary at this time. Therefore, PHMSA is not proposing to issue any new regulations for underground storage of hazardous liquids in this proceeding. Order in Which Regulatory Changes Should Be Made in to Best Protect the Public, Property, or the Environment Comments PHMSA received comments from industry, trade associations, one government/municipality, and one regulatory association responding to the question on the order of the actions PHMSA should take to best protect the public, property, or the environment. API–AOPL, supported by TransCanada Keystone and the trade associations, OIPA, TxOGA, and LMOGA, indicated that PHMSA’s actions should be riskbased. Similarly, NAPSR had no recommendation on the order, but suggested that it be based on risk. The government/municipality NSB requested that PHMSA place a high priority on the repeal of regulatory exceptions for gathering of hazardous liquids in rural areas, offshore pipelines in state waters, and producer-operated lines on the OCS. NSB stated that unregulated rural pipelines are located in Unusually Sensitive Areas (USAs) of the NSB. These pipelines cross sensitive arctic tundra vegetation and impact areas used by endangered species. As North Slope development continues to expand to the west, east, and south, E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules impacts to NSB communities and USAs will increase. Response PHMSA is proposing to repeal the exception for gravity lines and to apply the reporting requirements in part 195 to all gathering lines. B. Definition of High Consequence Area In the ANPRM, PHMSA asked for public comment on whether to modify the requirements in part 195 for HCAs. Specifically, PHMSA asked whether: • The criteria for identifying HCAs should be changed to incorporate additional pipeline mileage or better reflect risk; • All navigable waterways should be included within the definition of an HCA; • The process for making HCA determinations on pipeline ROWs can be improved; • The public and state and local governments should be more involved in making HCA determinations; • Additional safety requirements should be developed for areas outside of HCAs; and • Major road and railway crossings should be included within the definition of an HCA. As discussed in detail later in the Background and NPRM Proposals section, PHMSA is proposing to adopt additional safety standards for pipelines that are located outside of areas that could affect an HCA. These measures will increase the safety of all of the nation’s pipelines without necessitating any change to the HCA definition; therefore, PHMSA is not taking any further action on that proposal at this time. Expanding the Definition of HCA To Include Additional Pipeline Mileage In the ANPRM, PHMSA asked whether the current criteria for identifying HCAs should be modified to incorporate additional pipeline mileage. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Comments TransCanada Keystone recommended that PHMSA further define the meaning of an HCA, and that the agency provide greater clarity with respect to the HCA classification, including the magnitude of impacts that differentiate HCAs from other areas. API–AOPL, supported by the trade associations, TxOGA and LMOGA, and an industry commenter, TransCanada Keystone, stated that the current criteria should not be changed. API–AOPL stated that PHMSA should serve a clearinghouse function by displaying HCA information on the NPMS, with VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 updates every 10 years based on census information. API–AOPL further noted that ‘‘other populated areas’’ includes Census-delineated areas, like Metropolitan Statistical Areas (MSA) and Consolidated Metropolitan Statistical Areas, which are not densely populated, and that the current HCA criteria are thus conservative. API– AOPL also stated that the current ability of operators to demonstrate why segments of pipeline could not affect an HCA should be retained. The trade associations, OIPA and TPA, suggested that more data is needed to make a decision on HCA definition expansion, and that any changes would likely impact small operators. Among citizens’ groups, PST favored expanding the IM requirements to all hazardous liquid lines, with initial inspections required within 5 years of identification. PST stated that using census data to designate high population and other population areas is arbitrary and not necessarily a predictor of risk. Noting that the public could not fully comment because HCA boundaries are not publicly available (for security reasons); PST stated that the definition of HCA should be expanded to include national parks, monuments, recreation areas, and national forests. PST also pointed to the recent trend in extreme accidents in HCAs. Two other citizens’ groups, AKW and NRDC, commented. AKW requested that the criteria be changed. NRDC indicated that PHMSA should have a broader definition of HCAs, particularly with respect to ecological resources and drinking water criterion. NAPSR commented that the current criteria are generally adequate, but that other threats and risks could be considered, including petroleum product supply loss, leaks that could affect private wells, and impacts to major infrastructure. NSB favored an expansion of HCAs to include pipelines located in subsistence areas, cultural resources, archeological, historical, and recreational areas of significance and offshore. Response Congress recently directed the Secretary to prepare a report on whether the IM requirements should be extended to pipelines outside of areas that could affect HCAs. The Secretary is prohibited from issuing any final regulations that would expand those requirements during a subsequent Congressional review period, unless those regulations are necessary to address a condition posing a risk to public safety, property, or the environment, or an imminent PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 61621 hazard. PHMSA is preparing the Secretary’s report to Congress on the need to expand the IM requirements and is not proposing to change the definition of an HCA to incorporate additional pipeline mileage at this time. PHMSA is, however, proposing to adopt additional safety standards for pipelines that are not covered under the IM program requirements. The proposals are detailed later in this NPRM under the Background and NPRM proposals section. PHMSA is aware of its obligation to consider other locations near pipeline ROWs in defining USAs, including ‘‘critical wetlands, riverine or estuarine systems, national parks, wilderness areas, wildlife preservation areas or refuges, wild and scenic rivers, or critical habitat areas for threatened and endangered species.’’ However, PHMSA is not proposing to make any of these areas USAs in light of the new requirements that are being proposed for non-IM pipelines. PHMSA will be considering whether to include these locations in the HCA definition in performing the evaluation required under section 5 of the Pipeline Safety Act of 2011 and will comply with the applicable provisions of that legislation before taking any final regulatory action to adopt the proposed requirements for non-IM pipelines. Modifying the Definition of HCA to Better Reflect Risk PHMSA asked whether the criteria for identifying HCAs should be changed to better reflect risk. Comments TransCanada Keystone’s comment focused specifically on the classification of groundwater USAs in § 195.6, stating that groundwater HCA buffers should not be expanded, and that the existing criteria, which identify community water intakes where contamination has the potential to cause greater impacts compared to other areas, are sufficient. API–AOPL stated that there are various risk factors applicable to HCA classifications and that the current definition should not be changed. API– AOPL recommended that buffer zones be used as an acceptable alternative to the more detailed ‘‘could affect’’ analysis for new, expanded, or modified HCAs. API–AOPL also suggested that operators should retain the ability, with technical justification, to determine whether a pipeline can actually impact an HCA. TransCanada Keystone, LMOGA, and TxOGA endorsed API– AOPL’s comments. TPA, the other trade association commenter, mentioned that E:\FR\FM\13OCP3.SGM 13OCP3 61622 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules more data was needed to make a final decision on this matter. A number of citizens’ groups commented on this issue. NRDC, AKW, and TWS indicated the HCA definition needs to be broadened to reflect risk and to include entire pipelines in some cases. NRDC stated that the threshold for a populated area should be lowered, and that the definition of populated areas and USA should be improved. NRDC commented that the current HCA definition provides limited protection to threatened or endangered species. NRDC also recommended strengthening the USA definition to protect more migratory bird areas and national landmarks, including national parks, wild and scenic rivers, estuaries, wilderness areas, wildlife refuges, and drinking water sources, including private wells and open source aquifers. TWS and AKW proposed to revise the HCA criteria to include all transportation infrastructure, public lands, waterways, wetlands, and cultural, historic, archeological, and recreation sites, including subsistence areas. NAPSR stated that the current HCA definition should not be changed, but that PHMSA should consider incorporating others threats and risks, including supply interruptions and small leaks that could affect private wells. NSB favored changing the existing HCA definition. NSB stated that USAs should include subsistence, cultural, archeological, historical, and recreational areas of significance within the NSB and offshore waters of the Beaufort and Chukchi Seas. NSB suggested a formal process for nominating areas that should be afforded HCA status, and that the NPMS data should be updated. Both MAWUC and DLA indicated the definition could be modified to better reflect risk. MAWUC suggested a tiered, prioritized system with enforceable criteria that are appropriate for the risk to water supplies. DLA stated that higher risk locations should be protected instead of simply creating more HCAs. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Response PHMSA is not proposing to make any changes to the criteria for identifying HCAs at this time. The existing Censusbased approach for determining high population and other populated areas ensures uniformity and provides an adequate margin of safety by including some less densely populated areas. None of the commenters offered a more effective alternative. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 PHMSA recognizes that other areas of ecological, cultural, or national significance could be designated as USAs. However, PHMSA is not proposing to add any of these areas in light of the new safety standards that are being proposed for hazardous liquid pipelines that are not subject to the IM program requirements. PHMSA does not support any of the suggested alternative approaches for identifying HCAs. The widespread use of the buffer method is not justified based on the available information, and the use of a more lenient standard in making HCA determinations would not provide adequate protection for these sensitive areas. PHMSA will revisit these conclusions in preparing the Secretary’s report to Congress on expanding the IM program for hazardous liquid pipelines. Commercial Limitation on Navigable Waterways The ANPRM posed the question of expansion of the definition of HCAs beyond commercially navigable waterways. Comments Several trade associations, API– AOPL, OIPA, and IPAA, and one industry representative, TransCanada Keystone, opposed expanding the HCA definition beyond commercially navigable waterways. These commenters stated that the vast majority of surface waters are already covered under the present criteria. TPA stated that adopting a navigable waters standard would make every creek an HCA, resulting in a significant increase in the burden associated with implementing IM requirements. Two citizens’ groups commented on the phrase ‘‘commercially navigable.’’ PST also recommended defining HCA to include all ‘‘waters of the United States,’’ provided PHMSA did not adopt its suggestion to apply IM requirements to all regulated pipelines. NRDC proposed to amend the term ‘‘commercially navigable waterways’’ to include other bodies of water that are not necessarily navigable, such as lakes, streams, and wetlands. Two government/municipalities commented on the commercial limitation on navigable waterways. DLA, a government/municipality, echoed the comments of the trade associations and TransCanada Keystone previously mentioned. NSB requested PHMSA change commercially navigable to ‘‘navigable waters’’ or ‘‘waters of the U.S.’’ to encompass more environmentally-sensitive areas. PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 Response Section 195.450 states that an HCA includes any ‘‘waterway where a substantial likelihood of commercial navigation exists.’’ RSPA first proposed to include commercially navigable waterways as HCAs in the April 2000 NPRM that contained the original IM requirements for hazardous liquid pipelines April 24, 2000, (65 FR 21695). RSPA stated that it ‘‘[wa]s including commercially navigable waterways in the proposed [HCA] definition[,] [b]ecause these waterways are critical to interstate and foreign commerce and supply vital resources to many American communities, are a major means of commercial transportation, and are a part of a national defense system, a pipeline release in these areas could have significant impacts.’’ April 24, 2000, (65 FR 21700). RSPA adopted the HCA definition as proposed in the NPRM in the final rule December 1, 2000, (65 FR 75378). In the preamble to that final rule, RSPA stated that it had received the following comments on its proposal to include commercially navigable waterways in the HCA definition: API and liquid operators questioned the inclusion of commercially navigable waterways into the HCA’s definition. API pointed out that Congress required OPS to identify hazardous liquid pipelines that cross waters where a substantial likelihood of commercial navigation exists and once identified, issue standards, if necessary, requiring periodic inspection of the pipelines in these areas. API said that OPS had not determined the necessity for including these waterways in areas that trigger additional integrity protections. BP Amoco said the rule should be limited to protection of public safety, rather than commercial interests. Enbridge and Lakehead also questioned why waterways that are not otherwise environmentally sensitive should be included for protection. EPA Region III said that we should also consider recreational and waterways other than those for commercial use. Environmental Defense, Batten, City of Austin and other[s] commented that we should consider all navigable waterways as HCA’s, because of the environmental consequences a hazardous liquid release could have on such waters. December 1, 2000, (65 FR 75390). RSPA provided the following response to those comments: ‘‘Our inclusion of commercially navigable waterways for public safety and secondary reasons is not based on the ecological sensitivity of these E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules waterways. Parts of waterways sensitive for ecological purposes are covered in the proposed USA definition, to the extent that they contain occurrences of a threatened and endangered species, critically imperiled or imperiled species, depleted marine mammal, depleted multi-species area, Western Hemispheric Shorebird Reserve Network or Ramsar site. We are including commercially navigable waterways as HCAs because these waterways are a major means of commercial transportation, are critical to interstate and foreign commerce, supply vital resources to many American communities, and are part of a national defense system. A pipeline release could have significant consequences on such vital areas by interrupting supply operations due to potentially long response and recovery operations that occur with hazardous liquid spills. December 1, 2000, (65 FR 75391–2). For these reasons, RSPA defined HCAs in § 195.450 to include commercially navigable waterways. Thus, the Pipeline Safety Laws do not necessarily limit the definition of an HCA to commercially navigable waterways. RSPA relied on several statutes in promulgating the IM requirements for hazardous liquid pipelines, including the mandates that required the Secretary to establish criteria for identifying pipelines in high density population and environmentally sensitive areas (49 U.S.C. 60109(a)(1)) and to promulgate standards for ensuring the periodic inspection of these lines (49 U.S.C. 60102(f)(2)). Nothing in these provisions or the Pipeline Safety Act of 2011 prohibits PHSMA from using its general rulemaking authority to apply the hazardous liquid pipeline IM regulations to waterways that are not used for commercial navigation. Other kinds of waterways are also referenced in the statutory criteria that must be considered in defining USAs. PHMSA will be considering the expansion of current HCA or the extension of critical IM requirements to non-HCAs-when completing the Secretary’s report to Congress on the need to expand the IM requirement under section 5 of the Pipeline Safety Act of 2011. In the meantime, PHMSA is not proposing to include any additional waterways in the HCA definition. PHMSA is, however, proposing to adopt other regulations that will increase the safety of our nation’s waterways. One such proposal is to require leak detection systems for pipelines in all locations, that operators VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 perform periodic assessments of pipelines not already covered under the IM program requirements, and that new pipeline repair criteria be applied to anomalous conditions discovered in all areas. Another proposal is to require operators to inspect their pipelines in areas affected by extreme weather, natural disasters, and other similar events (e.g., flooding, hurricanes, tornados, earthquakes, landslides, etc.). Following a disaster event, operators will be required to determine whether any conditions exist that could adversely affect the safe operation of a pipeline and to take appropriate remedial actions, such as reductions in operating pressures and repairs of any damaged facilities or equipment. In regard to seismic events and earthquakes, in determining whether a pipeline has potentially been affected and needs inspection, operators should consider relevant factors such as magnitude of the earthquake, distance from the epicenter, and pipeline characteristics and history. PHMSA recognizes that after considering these factors, operators may determine that smaller seismic events do not have the potential to affect their pipelines. Based on available studies, however, earthquakes over 6.0 in magnitude can potentially damage pipelines and operators would be required to inspect these pipelines. Operator Process and Public Participation in Making HCA Determinations PHMSA requested comment on whether the operator’s process for making HCA determinations should be modified, including by having greater involvement by the public and state and local governments. Comments PHMSA received comments from industry, trade associations, and one regulatory association. API–AOPL supported the existing process for identifying HCAs and suggested that any input from local communities should be through the regulating agency, rather than pipeline operators. OPIA and IPAA noted that a consistent and reliable approach is needed to prevent variations that would result in unnecessary confusion. The trade associations, TxOGA, LMOGA, API–AOPL, supported by TransCanada Keystone, indicated that operators perform geographic overlay of their pipeline systems with PHMSAdetermined HCAs. Operators also utilize the ‘‘could affect’’ analysis, which typically considers technical assessments using dispersion models. PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 61623 Through the process of HCA evaluation, operators are sometimes able to determine, with technical justification, that their assets are not capable of impacting an HCA. NAPSR indicated that PHMSA could consider adding minimum time intervals for operators to review HCA identifications, including a shorter time interval if a pipeline is routed through high population areas. NAPSR also stated that there are areas where private wells have been extremely affected by small leaks that go undetected for years, that this is especially true in areas of sandy soil where leaks do not necessarily bubble up to the surface, and that there should be some consideration to address these ‘‘seepers’’ that have very large total leak volume over time. On the matter of greater public participation, TransCanada Keystone suggested that PHMSA collect data from the states and provide updated HCA information for operator use. The trade associations, LMOGA, TxOGA and API– AOPL, supported by TransCanada Keystone, recommended that additional local involvement be routed through the regulating agency, such as PHMSA. TPA, in contrast, stated that there should be no requirement for public involvement. OIPA and IPAA held that a consistent and reliable approach is needed for the issue of public involvement. Among the citizens’ groups, NRDC supported additional public involvement. Several commenters, including NRDC, PST, and TWS, recommended that the NPMS be revised to display all HCAs so that the public can be better informed. One regulatory association, NAPSR, suggested that the public be allowed to comment. NAPSR recognized that PHMSA has a process in place for HCA selection that can be enhanced if the public is allowed to provide input. NAPSR stated that the general public and local communities often recognize changes in areas near pipelines before operators. Government and municipal commenters supported local involvement in the HCA determination process. MAWUC commented that it is important that local communities and water suppliers play a role in preventing and minimizing pipeline failures, including HCA identification. DLA also supported additional public involvement. NSB recommended that state and local governments, as well as local tribes, villages, and the Alaskan Eskimo Whaling Commission, have a role in making HCA determinations. E:\FR\FM\13OCP3.SGM 13OCP3 61624 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules Response Congress included new requirements for promoting public education and awareness in section 6 of the Pipeline Safety Act of 2011. Specifically, that provision requires PHMSA (1) to maintain, and update on a biennial basis, a map of designated HCAs in the NPMS; (2) to establish a program that promotes greater awareness of the existence of the NPMS to state and local emergency responders and other interested parties, to include the issuance of guidance on using the NPMS to locate pipelines in communities and local jurisdictions; and (3) to issue additional guidance to owners and operators of pipeline facilities on the importance of providing system-specific information to emergency response agencies. PHMSA believes that such actions will address many of the concerns raised by the commenters. Additional Safety Requirements for Non-HCA Areas PHMSA inquired as to whether additional safety measures should be developed for areas outside of HCAs. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Comments PHMSA received comments from three trade associations and one regulatory association. TransCanada Keystone, TxOGA, API–AOPL, and LMOGA indicated that no new requirements are necessary for areas outside of HCAs. The regulatory association, NAPSR, remarked that operators should be precluded from turning off in-line inspection sensors outside of an HCA when performing an integrity assessment under the IM regulations. Response PHMSA agrees with the NAPSR comment and has likewise found that some operators do turn off inspection tools outside of HCAs. Therefore, PHMSA is proposing to require that operators perform periodic assessments of pipelines that are not already covered under the IM program requirements in § 195.452. Promulgation of such a requirement will ensure that pipeline operators obtain the information necessary for the prompt detection and remediation of corrosion and other deformation anomalies (e.g., dents, gouges, and grooves) in all locations, not just in areas that could affect HCAs. Inclusion of Major Road and Railway Crossings as HCAs PHMSA requested comment on the need to include major road and railway crossings as HCAs. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Comments Industry, three trade associations, three citizens’ groups, one regulatory association, one government/ municipality, and one citizen commented on this question. TransCanada Keystone, supported by the trade associations, API–AOPL, TPA, TxOGA, and LMOGA, opposed including major roads and railway crossings as HCAs. The commenters offered several reasons to support that position (e.g., such a change would draw resources from other more high risk areas, non-HCA areas are already assessed and remediated, and there is no data to support such an action). Among the citizens’ groups, PST stated that rail and major road crossings should be included. TWS and AKW stated that all transportation infrastructure, public lands, wetlands under the Clean Water Act (CWA), cultural, historical, archeological and recreation areas used for subsistence be included in HCAs. NAPSR also suggested that rail and major road crossings should be included. NAPSR urged PHMSA to consider the effect of a release on electric transmission facilities, gas pipelines, and railroads if major road and rail crossings were not to be included in HCAs. NAPSR would consider the effect of a release on electric transmission facilities, gas pipelines, railroads, etc., and would treat major road and rail crossings as HCAs for highly volatile liquids (HVLs) pipelines. The only government/municipality to comment on this question was DLA. DLA indicated that these structures should be included in HCAs. Citizen Coyle commented that major roadways should be HCAs because these areas could be affected by pipelines carrying HVLs that would produce poisonous clouds if released. Response PHMSA is not proposing to designate major road and railway crossings as HCAs, but will consider whether the pipeline IM requirements should be applied to these areas when completing the study that Congress mandated under section 5 of the Pipeline Safety Act of 2011. PHMSA notes that the pipelines at such crossings would be afforded additional protections under the other proposals made in this proceeding, including the requirements for the performance of periodic internal inspections and the use of leak detection systems. PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 C. Leak Detection Equipment and Emergency Flow Restricting Devices In the ANPRM, PHMSA asked for comment on whether to modify the current requirements part 195 for leak detection equipment and emergency flow restricting devices (EFRDs). Specifically, PHMSA asked whether • The use of leak detection equipment should be required for hazardous liquid pipelines; • The pipeline industry has developed any practices, standards, or leak detection technologies that should be incorporated by reference; • Any industry practices or standards adequately address the relevant safety considerations; • State regulations for leak detection should be adopted by regulation; • Any new leak detection requirements should vary based on the sensitivity of the affected areas; • The pipeline industry has developed standards or practices for the performance and location of EFRDs; • The location of EFRDs should be specified by regulation; and • Additional research and development is needed to demonstrate the suitability of any new leak detection technologies. As discussed below, PHMSA is considering requiring that all hazardous liquid pipelines have a system for detecting leaks and expand the use of EFRDs. Expansion of Leak Detection Requirements In the ANPRM, PHMSA asked for comment on whether the agency should expand the leak detection requirements. Comments Industry and trade associations generally supported expansion of the existing requirement in § 195.452(i)(3) to most pipelines, but opposed including more-specific requirements in the regulations. API–AOPL, TxOGA, TransCanada Keystone, and LMOGA supported extending leak detection requirements to all PHMSA-regulated pipelines, except for rural gathering lines. Citizens’ groups supported enhanced leak detection requirements. TWS and PST opposed additional reliance on the current requirements in § 195.452(i)(3), stating that this regulation includes no acceptance criteria and is virtually unenforceable. TWS further supported expanding leak detection requirements to all pipelines under PHMSA jurisdiction. NRDC indicated that leak detection requirements should be expanded to include a requirement that E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules worst-case-discharge-pumping times be based on historical shutdown times, rather than expected times. NRDC also said that operators should immediately contact first responders at the first sign of an issue. One citizen, Stec, suggested requiring use of ‘‘smart coating’’ with embedded conductors that would break to indicate coating damage and which could then trigger automatic response actions. The regulatory associations, DLA and MAWUC, supported expanded leak detection requirements. MAWUC suggested PHMSA require the use of leak detection equipment in all HCAs. DLA indicated that any new requirements should be delayed until better technology is available. The government/municipality, NSB, recommended leak detection requirements be expanded to all pipelines under PHMSA regulation. NSB encouraged adoption of more stringent leak detection requirements for sensitive offshore areas of the Beaufort and Chukchi seas. Response As discussed earlier in this NPRM under the Background and Proposals section, PHMSA will propose to expand the leak detection requirements for HCA and non-HCA areas. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Consideration of New Industry Standards or Practices in Leak Detection PHMSA asked for public comment on whether any new industry standards or practices should be considered for adoption in part 195. Comments API–AOPL, TxOGA, LMOGA, and TransCanada Keystone all indicated that the API–AOPL standard RP1165 (SCADA), RP 1167 (Pipeline Alarm Management), and RP1168 (Control Room Management) are good standards to utilize for leak detection systems. API–AOPL also pointed out that many new technologies are being developed and existing methodologies are continuously being improved for better leak detection capability; however, many of these new technologies have not been proven in service on crosscountry pipelines. One citizens’ group, NRDC, commented that new leak detection standards should address the additional demands posed by hazardous liquids. In particular, NRDC mentioned some hazardous liquids, such as diluted bitumen, have multiphase properties that can cause false alarms. The regulatory associations, NAPSR and DLA, both commented on new industry standards and practices in leak VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 detection. NAPSR mentioned the new technology forward-looking infrared radar (FLIR) and encouraged PHMSA to consider using such new technologies. NAPSR reported that FLIR can detect changes in temperature near a pipeline from a winter leak, even under snow, and that it can be used from aerial patrols. DLA indicated that any leak detection standards should be third-party validated and listed by the National Work Group on Leak Detection Evaluations (NWGLDE) and that leak detection in general for large volume pipelines is not very effective at this time. Response The commenters only offered three specific industry standards or practices for consideration, and two of those standards, API RP1165 (SCADA) and RP1168 (Control Room Management), are already incorporated into part 195 (see 49 CFR 195.3). PHMSA has concerns about the adequacy and enforceability of the third standard, API RP 1167 (Pipeline Alarm Management), and does not believe that it should be incorporated by reference at this time. As previously discussed, PHMSA is proposing to require that operators have a means for detecting leaks on all portions of a hazardous liquid pipeline system. Consideration of FLIR and any other emerging technologies would be required in evaluating what kinds of leak detection systems are appropriate for a particular pipeline. PHMSA will also be considering whether the use of specific leak detection technologies should be required in preparing the Secretary’s report to Congress on that issue. PHMSA does not agree that thirdparty validation is a prerequisite to issuing new leak detection requirements for hazardous liquid pipelines. That limitation is not included in the Pipeline Safety Laws, and PHMSA does not believe that such action is necessary as a matter of administrative discretion. Adequacy of Existing Industry Standards or Practices for Leak Detection PHMSA asked for public comment on whether any existing industry standards or practices for leak detection are adequate for adoption into part 195. Comments TransCanada Keystone, TxOGA, LMOGA and API–AOPL submitted comments indicating that the current leak detection evaluations performed as a requirement of the IM program encompass many important factors for PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 61625 proper leak detection. PHMSA should allow for the implementation of recent regulatory changes, including the new Control Room Management (CRM) rule, before making any changes. NAPSR commented that all pipeline operators should, at a minimum, perform a tank balance periodically to detect leakage. NSB recommended that PHMSA adopt improved leak detection system standards and implement more stringent leak detection requirements for the sensitive offshore areas of the Beaufort and Chukchi seas. NSB stated that PHMSA should require: (1) Redundant leak detection systems for offshore pipelines; (2) All offshore pipeline leak detection systems to have the continuous capability to detect a daily discharge equal to not more than 0.5% of daily throughput within 15 minutes, and detect a pinhole leak within less than 24 hours; (3) All onshore pipeline leak detection systems to have the continuous capability to detect a daily discharge equal to not more than 1% of daily throughput within 15 minutes, and detect a pinhole leak within less than 24 hours; and (4) An initial performance test to verify leak detection accuracy upon installation and at regular intervals thereafter. Response PHMSA agrees that the factors listed in § 195.452(i)(3) are an appropriate basis for determining whether hazardous liquid pipelines have an adequate leak detection system and is proposing to use those factors as the basis for the requirements that would apply in all other locations. However, a December 31, 2007, report that PHMSA prepared in response to a mandate in the Pipeline Inspection, Protection, Enforcement, and Safety Act (PIPES Act) of 2006 (Pub. L. 109–468), confirmed that some operators had IM procedures that did not require the performance of a leak detection evaluation, and others had adopted an inadequate process for performing those evaluations. Operators are reminded that any failure to comply with part 195, including the leak detection requirements in § 195.452(i)(3) and the proposed modifications to §§ 195.134 and 195.444, increases both the likelihood and severity of pipeline accidents. PHMSA agrees that the new CRM requirements will improve the detection and mitigation of leaks on hazardous liquid pipeline systems, but does not agree that the implementation of improved leak detection requirements should be delayed solely on account of the recent issuance of those regulations. PHMSA will be monitoring the use of E:\FR\FM\13OCP3.SGM 13OCP3 61626 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules asabaliauskas on DSK5VPTVN1PROD with PROPOSALS leak detection systems by operators in complying with those requirements in determining if additional safety standards are needed. procedure for responding to alarms. The pipeline company must maintain leak detection maintenance and alarm records. Consideration of State Requirements/ Regulations for Leak Detection Some states have established leak detection requirements for hazardous liquid pipeline systems. For example, the Alaska Department of Environmental Conservation (ADEC) has promulgated a regulation (18 AAC 75.055) that states: (a) A crude oil transmission pipeline must be equipped with a leak detection system capable of promptly detecting a leak, including (1) if technically feasible, the continuous capability to detect a daily discharge equal to not more than one percent of daily throughput; (2) flow verification through an accounting method, at least once every 24 hours; and (3) for a remote pipeline not otherwise directly accessible, weekly aerial surveillance, unless precluded by safety or weather conditions. (b) The owner or operator of a crude oil transmission pipeline shall ensure that the incoming flow of oil can be completely stopped within one hour after detection of a discharge. (c) If above ground oil storage tanks are present at the crude oil transmission pipeline facility, the owner or operator shall meet the applicable requirements of 18 AAC 75.065, 18 AAC 75.066, and 18 AAC 75.075. (d) For facility oil piping connected to or associated with the main crude oil transmission pipeline the owner or operator shall meet the requirements of 18 AAC 75.080. Operators who install online leak detection systems can also receive a reduction in the volume of crude oil that must be used in complying with Alaska’s oil spill response planning requirements (18 AAC 75.436(c)(3)). The State of Washington has also prescribed leak detection requirements for hazardous liquid pipelines (WAC 480–75–300). Those requirements, which are administered by the Washington Utilities and Transportation Commission (WUTC), state: (1) Pipeline companies must rapidly locate leaks from their pipeline. Pipeline companies must provide leak detection under flow and no flow conditions. (2) Leak detection systems must be capable of detecting an eight percent of maximum flow leak within fifteen minutes or less. (3) Pipeline companies must have a leak detection procedure and a Comments PHMSA received comments from several trade associations and one citizens’ group on state requirements for leak detection systems. API–AOPL indicated that pipeline configuration and operational factors vary by geographic location, and that other variability exists, including fluid or product differences, batching, and other operational conditions. Due to these factors, any type of prescriptive approach to standards for leak detection is difficult to achieve and would be better served using a performance standard. CRAC noted that multi-phase lines are more susceptible to internal corrosion, and that state regulations do not require IM or leak detection. NAPSR and DLA also commented. NAPSR encouraged PHMSA to allow the states to set minimum leak detection criteria for intrastate pipelines. DLA opposed development of criteria based on state requirements and suggested that new requirements be third-party validated and listed by NWGLDE. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Response PHMSA favors the use of performance-based safety standards and believes that the regulations adopted by ADEC and WUTC show that certain minimum threshold requirements can be established for leak detection systems. PHMSA will be considering these and other similar regulations in an evaluation of leak detection systems. With regard to NAPSR’s comment, section 60104(c) of the Pipeline Safety Laws allows states that have submitted a current certification to adopt additional or more stringent safety standards for intrastate hazardous liquid pipeline facilities, so long as those requirements are compatible with the minimum federal safety standards. PHMSA has prescribed mandatory leak detection requirements for hazardous liquid pipelines that could affect HCAs and is proposing to make those requirements applicable to all pipelines subject to part 195. States that have submitted a current certification can establish additional or more stringent leak detection standards for intrastate hazardous liquid pipeline facilities, subject to the statutory compatibility requirement. PHMSA does not agree that thirdparty validation is a prerequisite to issuing new leak detection requirements for hazardous liquid pipelines. That limitation is not included in the PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 Pipeline Safety Laws, and PHMSA does not believe that such action is necessary as a matter of administrative discretion. Different Leak Detection Requirements for Sensitive Areas Section 195.452(i)(3) contains a mandatory leak detection requirement for hazardous liquid pipelines that could affect an HCA. That regulation requires operators to consider several factors (i.e., the length and size of the pipeline, type of product carried, proximity to the HCA, the swiftness of leak detection, location of nearest response personnel, leak history, and risk assessment results) in selecting an appropriate leak detection system. Comments PHMSA received many comments in response to whether there should be different leak detection requirements for sensitive areas. The trade associations, TxOGA and LMOGA, supported API– AOPL’s comments that most leak detection methods cannot target specific areas. API–AOPL further stated that leak detection for sensitive areas can be achieved through comprehensive riskbased evaluation, but that external monitoring is too invasive and is not yet proven or cost effective. The regulatory associations, government/municipalities, and citizens all supported increased leak detection requirements for sensitive areas. The regulatory association, NAPSR, mentioned the use of FLIR for sensitive areas and stated that special actions beyond patrols should be required for sensitive areas. DLA indicated leak detection standards should be thirdparty validated. MAWUC and a citizen, Coyle, recommended requiring external leak detectors in HCAs. Coyle would also require external leak detectors for above-ground pipelines transporting highly volatile liquids. NSB encouraged PHMSA to adopt improved leak detection standards and implement more stringent requirements for sensitive areas. Response PHMSA believes that the leak detection requirements in § 195.452(i)(3) can provide adequate protection for sensitive areas and is proposing to use those requirements as the basis for establishing requirements that would apply to hazardous liquid pipelines in all other locations. Under the current and proposed regulations, operators are required to consider several factors in selecting an appropriate leak detection system, including the characteristics and history of the affected pipeline, the capabilities of the available leak E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules detection systems, and the location of emergency response personnel. PHMSA commissioned Kiefner and Associates, Inc., to perform a study on leak detection systems used by hazardous liquid operators. That study, titled ‘‘Leak Detection Study,’’ 4 was completed on December 10, 2012, and was submitted to Congress on December 27, 2012. PHMSA is considering, in a different rulemaking activity, whether to adopt additional or more stringent requirements for sensitive areas in response to this study. Key Issues for New Leak Detection Standards asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Comments The trade associations, TxOGA, LMOGA, and API–AOPL, supported by an industry commenter, TransCanada Keystone, stated that PHMSA should identify issues that might adversely affect response times, including limiting the consequences for first responder deployment and allowing for the withdrawal of erroneous leak notifications. NAPSR, the only regulatory association to comment, found that any new standards should consider detection of small leaks in HCAs, maintenance, accuracy, transient conditions, system capabilities, and alarm management. Three government/municipalities commented on this issue. DLA stated that any standards should address sensitivity, probability of false alarms, minimum leak detection capabilities, frequency, and be based on leak detection technology. MAWUC supported more stringent reporting and repair requirements. NSB indicated that PHMSA should require redundant leak detection systems for offshore lines. NSB also indicated the technology available for leak detection systems is vastly improved and industry should bear the burden to utilize these systems. Response The Pipeline Safety Laws contain a number of general factors that must be considered in prescribing new safety standards, including the reasonableness of the standard, the estimated benefits and costs, and the views and recommendations of the Technical Hazardous Liquid Pipeline Safety Standards Committee (49 U.S.C. 60102(b)). The Pipeline Safety Laws also contain specific factors that must be considered in prescribing certain safety standards, such as for smart pigs (49 4 https://www.phmsa.dot.gov/pv_obj_cache/pv_ obj_id_4A77C7A89CAA18E285898295888E3DB9 C5924400/filename/Leak%20Detection%20Study. pdf VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 U.S.C. 60102(f)) or low-stress hazardous liquid pipelines (49 U.S.C. 60102(k)). In the case of leak detection, Congress has enacted prior statutory mandates that required the Secretary to survey and assess the need for additional safety standards. PHMSA and its predecessor agency, RSPA, complied with those mandates by producing two reports and promulgating additional safety standards for leak detection systems. Congress enacted a similar provision in section 8 of the Pipeline Safety Act of 2011, including a requirement that the Secretary submit a report to Congress that provides an analysis of the technical limitations of current leak detection systems and the practicability, safety benefits, and adverse consequence of establishing additional standards for the use of such systems. The commenters identified several issues that should be considered in establishing new leak detection standards, including the need to minimize false alarms, to set appropriate volumetric thresholds, and to encourage the use of best available technologies. Statistical Analyses of Leak Detection Requirements PHMSA asked the public to comment on the availability of statistics on whether existing practices or standards on leak detection have contributed to reduced spill volumes and consequences. Comments One response submitted by API– AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, stated that the association was unaware of any recent statistics in regard to this topic. API–AOPL further indicated that PHMSA should allow time for recent regulatory changes to take effect on the regulated population. Response PHMSA’s December 2007 report on leak detection systems noted that from 1997 to 2007 ‘‘the median volume lost from hazardous liquid pipeline accidents dropped by more than half, from 200 to less than 100 barrels,’’ and that ‘‘the number of accidents declined by over a third.’’ The report attributed that positive trend to the implementation of the pipeline IM requirements in § 195.452. However, the report also indicated that all of the available leak detection technologies have strengths and weakness, that some are only suitable for use on particular pipeline systems, and that establishing safety standards would require consideration of a number of factors. PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 61627 Consideration of Industry Practices or Standards for Location of EFRDs Part 195 requires that EFRDs be considered as potential mitigation measure on pipeline segments that could affect HCAs. In terms of §§ 195.450 and 195.452 the definition for check valve means a valve that permits fluid to flow freely in one direction and contains a mechanism to automatically prevent flow in the other direction. Likewise, remote control valve or RCV means any valve that is operated from a location remote from where the valve is installed. The RCV is usually operated by the supervisory control and data acquisition (SCADA) system. The linkage between the pipeline control center and the RCV may be by fiber optics, microwave, telephone lines, or satellite. Section 195.452(i)(4) further states that if an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, consider the following factors—the swiftness of leak detection and pipeline shutdown capabilities, the type of commodity carried, the rate of potential leakage, the volume that can be released, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest response personnel, specific terrain between the pipeline segment and the high consequence area, and benefits expected by reducing the spill size. RSPA adopted the EFRD requirements in §§ 195.450 and 195.452 in a December 2000 final rule December 1, 2000, (65 FR 75378). Part 195 does not require that EFRDs be used on pipelines outside of HCAs, but § 195.260 does require that valves be installed at certain locations. Congress included additional requirements for the use of automatic and remote-controlled shut-off valves in section 4 of the Pipeline Safety Act of 2011. That provision requires the Secretary, if appropriate and where economically, technically, and operationally feasible, to issue regulations for the use of automatic and remote-controlled shut-off valves on transmission lines that are newly constructed or entirely replaced. The Comptroller General is also required to perform a study on the effectiveness of these valves and to provide a report to Congress within one year of the date of the enactment of that legislation. PHMSA commissioned a study titled ‘‘Studies for the Requirements of E:\FR\FM\13OCP3.SGM 13OCP3 61628 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines With Respect to Public and Environmental Safety,’’ 5 to help provide input on regulatory considerations regarding the feasibility and effectiveness of automatic and remote-control shutoff valves on hazardous liquid and natural gas transmission lines. The study was completed by the Oak Ridge National Laboratory on October 31, 2012, and it was submitted to Congress on December 27, 2012. PHMSA is using considerations from this study as it drafts a rulemaking titled ‘‘Amendments to Parts 192 and 195 to require Valve installation and Minimum Rupture Detection Standards.’’ Comments PHMSA received comment on this issue from industry and trade associations. API–AOPL, TxOGA, LMOGA, and TransCanada Keystone reported that no industry standards currently address EFRD use, although ASME B31.4, ‘‘Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids’’ (2009), addresses mainline valves and requires remote operation and/or check valves in some instances. ASME B31.4 (2009) also has guidelines for mainline valves and requires remote and check valves, but is not currently incorporated by reference into part 195. Section 195.452 does require that operators identify the need for additional preventive and mitigation measures. Response PHMSA is studying issues concerning the development of additional safety standards for the use of EFRDs. PHMSA will consider the industry standards mentioned by the commenters, as well as the results of the September 1996 Volpe Report, the December 2007 Leak Detection Study, and the 2012 Oak Ridge National Laboratory study, for the purposes of any future rulemaking on the topic. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Adequacy of Existing Industry Practices or Standards for EFRDs PHMSA asked for comment on the adequacy of existing industry practices or standards for EFRDs. Comments API–AOPL, TxOGA, LMOGA, and TransCanada Keystone stated that there is no current industry standard that sets a maximum spill volume or activation 5 https://www.phmsa.dot.gov/pv_obj_cache/pv_ obj_id_ 2C1A725B08C5F72F305689E943053A96232AB200/ filename/Final%20Valve_Study.pdf VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 timing due to the widespread variation in pipeline dynamics; therefore, it would be difficult to establish a onesize-fits-all maximum spill volume requirement. API–AOPL suggests PHMSA should focus on prevention and response rather than spill size reduction through EFRDs. Response Section 195.452(i)(4) contains a requirement for the use of EFRDs on hazardous liquid pipelines that could affect an HCA. PHMSA agrees with the commenters that oil spill prevention and response are important to ensuring the safety of hazardous liquid pipelines, and believes that the appropriate use of EFRDs could be complementary to these efforts. Consideration of Additional Standards Specifying the Location of EFRDs Part 195 requires that EFRDs be considered as potential mitigation measure on pipeline segments that could affect HCAs, but it does not specify any particular location for the use of those devices. Operators must perform a risk analysis in determining whether and where to install EFRDs for such lines. Part 195 does not require that EFRDs be used on pipelines outside of HCAs. In the ANPRM, PHMSA asked for comment on whether additional standards should be developed to specify the location for EFRDs. Comments PHMSA received comments from four trade associations, one industry operator, and one regulatory association regarding prescriptive location of EFRDs. API–AOPL, TransCanada Keystone, LMOGA, and TxOGA indicated PHMSA should not specify location of EFRD placement for the reasons provided in response to previous questions. TPA agreed that no general criteria beyond those in existing regulations are appropriate because decisions on EFRD placement are driven by local factors. NAPSR supported the comments of the trade associations. Response PHMSA recognizes the commenters’ concerns about mandating the installation of EFRDs in particular locations, but notes that other provisions in part 195 require that valves and other safety devices be installed in certain areas. Mandated Use of EFRDs in All Locations PHMSA requested comment on mandated use of EFRDs in all locations under PHMSA jurisdiction. PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 Comments API–AOPL, TransCanada Keystone, LMOGA, and TxOGA indicated that a requirement to place EFRDs at predetermined locations or fixed intervals would be arbitrary, costly, and potentially counterproductive to pipeline safety. They noted that not all valves are mainline valves, and that a requirement for all valves to be remote would cause confusion. Many valves are at manned facilities. Some EFRDs are check valves, which are not amenable to remote control. API–AOPL noted that costs related to providing remote operation would vary based on proximity to power and communications, but that a December 2010 study by the Congressional Research Service estimated retrofit costs of $40K to $1.5M per valve. NAPSR agreed with the comments supplied by the trade associations and TransCanada Keystone. Finally, NSB stated EFRDs should be required on all pipelines PHMSA regulates with specific instruction on when and where EFRDs need to be utilized. Response PHMSA recognizes the commenters’ concerns about mandating the installation of EFRDs in all locations and plans on continuing to study this issue. Additional Research for Leak Detection PHMSA requested comment regarding what leak detection technologies or methods require further research and development to demonstrate their efficacy. Comments PHMSA received no comments in response to this question. D. Valve Spacing Valve Spacing The ANPRM asked whether PHMSA should repeal or modify the valve spacing requirements in part 195. Specifically, the ANPRM asked: • For information on the average distance between valves; • Whether valves are manually operated or remotely controlled; • Whether additional standards should be adopted for evaluating valve spacing and location; • Whether the maximum permissible distance between valves should be specified by regulation; • Whether to adopt additional valve spacing requirements for hazardous liquid pipelines near HCAs; • Whether additional valve spacing requirements should be adopted to protect narrower bodies of water; E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules • Whether all valves should be remotely controlled; and • What the cost impact would be from requiring the installation of certain types of valves. As discussed below, PHMSA is not proposing to adopt any additional standards for valve spacing, but will be considering that issue in complying with the various mandates in the Pipeline Safety Act of 2011. Part 195 contains general construction requirements for valves. Specifically, § 195.258 provides that each valve must be installed in a location that is accessible to authorized employees and protected from damage or tampering. This section further states that submerged valves located offshore or in inland navigable waters must be marked, or located by conventional survey techniques, to facilitate quick location when operation of the valve is required. PHMSA pipeline safety regulations found in section 195.260 indicate that a valve must be installed at certain locations. The locations named include on the suction end and the discharge end of a pump station or a breakout storage tank area in a manner that permits isolation of the tank area from other facilities and on each mainline at locations along the pipeline system that will minimize damage or pollution from accidental hazardous liquid discharge, as appropriate for the terrain in open country, for offshore areas, or for populated areas. Three additional requirements for valve location in section 195.260 include each lateral takeoff from a trunk line, on each side of a water crossing that is more than 100 feet (30 meters) wide from high-water mark to high-water mark and on each side of a reservoir holding water for human consumption. The Department adopted these regulations in an October 1969 final rule October 4, 1969, (34 FR 15475). As discussed in section 3, part 195 requires the use of EFRDs as a potential mitigation measure on pipeline segments that could affect HCAs. As also discussed in section 3, Congress included new provisions for the use of automatic and remote-controlled shutoff valves and leak detection systems in the Pipeline Safety Act of 2011. Comments The commenters did not provide any data on the average distance between valves, but did provide general information on valve spacing, location, and type. The commenters further noted that ASME B31.4, a consensus industry standard, includes a minimum valve spacing requirement of 7.5 miles for liquefied petroleum gas (LPG) and anhydrous ammonia pipelines in populated areas. Specifically, API–AOPL, LMOGA, TxOGA, and TransCanada Keystone stated that valve spacing varies, that most mainline valves are manually operated, that check valves are used in certain cases, and that some remotely controlled valves had been added as a result of the IM requirements. API– AOPL also commented that ASME B31.4 provides additional requirements for LPG and anhydrous ammonia in populated areas, including a 7.5-mile spacing requirement for valves, but noted that PHMSA had not incorporated this version of B31.4 into part 195. NAPSR stated that proper valve location is more important than distance placement. Information on Average Distance Between Valves and Manual or Remote Operation Response Part 195 requires the installation of valves at certain locations, including pump stations, breakout tanks, mainlines, lateral lines, water crossings, and reservoirs. These requirements are generally directed toward achieving a particular result (e.g., isolation of a facility, minimization of damage or pollution, etc.) and do not mandate that valves be installed at specific distances. Part 195 does not prescribe whether manual or remotely controlled valves must be installed at particular locations, but does require consideration of check valves and remotely controlled valves under the EFRD requirements for pipelines that could affect an HCA. Section 4 of the Pipeline Safety Act of 2011 includes new requirements for evaluating and issuing additional regulations for the use of the automatic and remote-controlled shut-off valves. PHMSA is not proposing to make any changes to the current valve spacing requirements at this time. A coordinated analysis will ensure that these issues are addressed in a way that maximizes the potential benefits and minimizes the potential burdens imposed by any new leak detection and valve spacing standards. PHMSA asked the public to provide information on the average distance between valves and whether such valves are manually operated or remotely controlled. Adoption of Additional Standards for Valve Spacing and Location PHMSA asked for comment on the adoption of additional standards for valve spacing and location. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 61629 Comments TransCanada Keystone, API–AOPL, TxOGA, and LMOGA stated that the standards in §§ 195.260 and 195.452 are satisfactory. NAPSR supported the comments of API–AOPL. NSB recommended that DOT adopt standards for pipeline operators to use in evaluating valve spacing and location and identifying the maximum distance between valves. Response PHMSA is not proposing to adopt any additional standards for valve spacing and locations, but will be considering that issue in complying with the various mandates in the Pipeline Safety Act of 2011. PHMSA held a public meeting/ workshop on valve spacing and locations on March 28, 2012. Information from this workshop was used in Oak Ridge National Laboratory’s study, completed October 31, 2012, titled: ‘‘Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines with Respect to Public and Environmental Safety’’ 6 to help determine the need for additional valve and location standards. Additional Standards for Specifying the Maximum Distance Between Valves PHMSA asked for public comment on whether part 195 should specify the maximum permissible distance between valves. Comment API–AOPL, TxOGA, LMOGA, TransCanada Keystone, and TPA opposed such a requirement and stated that valve spacing should be based on conditions and terrain. NAPSR also supported this position. NSB and MAWUC recommended the DOT adopt specific valve spacing standards. MAWUC stated that the criteria for valve spacing should be developed, but that the precise location of valves should not be made publicly available. Response Similarly, PHMSA is not proposing to adopt any additional standards for valve spacing at this time. PHMSA will be studying this issue and may make proposals concerning this topic in a later rulemaking. 6 https://www.phmsa.dot.gov/pv_obj_cache/pv_ obj_id_ 2C1A725B08C5F72F305689E943053A96232AB200/ filename/Final%20Valve_Study.pdf E:\FR\FM\13OCP3.SGM 13OCP3 61630 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules Response Additional Requirements for Valve Spacing Near HCAs Beyond Those Required for EFRDs PHMSA asked for public comment on whether part 195 should contain additional requirements for valve spacing in areas near HCAs beyond what is already required in § 195.452(i)(4) for EFRDs. Comments NSB encouraged PHMSA to adopt additional requirements for these areas. Taking a contrary position, API–AOPL, LMOGA, TxOGA, NAPSR, and TransCanada Keystone indicated that the current requirements adequately address the need for EFRDs and allow operators to assess the specific risks on each individual pipeline that could affect an HCA. Response PHMSA does not propose to make any changes to the regulations concerning the valve spacing at this time. PHMSA will be studying this issue and may make proposals concerning this topic in a later rulemaking. Modifying the Scope of 49 CFR 195.260(e) To Include Narrower Bodies of Water Section 195.260(e) requires the installation of a valve ‘‘[o]n each side of a water crossing that is more than 100 feet (30 meters) wide from high-water mark to high-water mark unless the Administrator finds in a particular case that valves are not justified.’’ The Department adopted that requirement in an October 1969 final rule October 4, 1969, (34 FR 15475) after adding the provision that allows the Administrator to find that the installation of a valve is not justified in specific cases. Such a finding requires the filing of a petition with the Administrator under 49 CFR 190.9. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Comments API–AOPL, TxOGA, LMOGA, and TransCanada Keystone indicated that the current water crossing requirements are adequate, but that PHMSA could improve the regulation by allowing a risk-based approach for valve placement at water crossings and adding an exclusion for carbon dioxide pipelines. TWS stated that PHMSA should require valves for waterways that are at least 25-feet in width and all feeder streams and creeks leading to such waterways. NSB supported the view of TWS and indicated the current 100-foot threshold for waterways should be reduced to 25 feet. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 As mentioned previously, PHMSA is proposing that all pipelines be inspected after extreme weather events or natural disasters. This is a natural extension of IM and ensures continued safe operations of the pipeline after abnormal operating conditions. Past events have strongly demonstrated that inspections after these events do prevent pipeline incidents from occurring. PHMSA is also proposing to require that all hazardous liquid pipelines have leak detection systems; that pipelines in areas that could affect HCAs be capable of accommodating ILIs within 20 years, unless the basic construction of the pipeline will not permit such an accommodation; that periodic assessments be performed of pipelines that are not already receiving such assessments under the IM program requirements; and that modified repair criteria be applied to pipelines in all locations. PHMSA will comply with the applicable provisions in the Pipeline Safety Act of 2011 before adopting any of these proposals in a final rule. Adopting Safety Standards That Require All Valves To Be Remotely Controlled PHMSA asked the public to comment on whether part 195 should include a requirement mandating the use of remotely-controlled valves in all cases. Comments API–AOPL, LMOGA, and TxOGA stated that PHMSA should not require remotely controlled valves in all cases. API–AOPL indicated that such a requirement would cause confusion as to which valves need to be operated manually, burden the industry with additional costs, and provide minimal safety benefits. API–AOPL submitted that the costs of retrofitting a valve to be remotely controlled varies widely from $40,000 to $1.5 million per valve as indicated in a recent report issued by the Congressional Research Service on pipeline safety and security. TPA further stated that the benefits of such requirements are dependent on local factors, and that additional requirements would add to pipeline system complexity and increase the probability of failure. Similarly, NAPSR stated that remote control valves should not be required, but that PHMSA should consider performance language for maximum response time to operate manual valves. MAWUC indicated that PHMSA should consider requiring all valves to be remotely controlled, but that its decision should be based on an analysis of benefits and risks. NSB supported the PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 use of remotely controlled valves in all instances. Coyle, a citizen, commented that PHMSA should promulgate regulatory language requiring remotely controlled valves for poison inhalation hazard pipelines. Response PHMSA notes that a risk-assessment must be performed in developing any new safety standards for the use of remotely controlled valves, and that any such standards will only be proposed upon a reasoned determination that the benefits justify the costs. Requiring Installation of EFRDs To Protect HCAs Section 195.452(i)(4) does not require the installation of an EFRD on all pipeline segments that could affect HCAs. Rather, it states that ‘‘[i]f an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must install the EFRD.’’ It also states that an operator must at least consider a list of factors in making that determination. Comments API–AOPL, LMOGA, TxOGA and TransCanada Keystone stated that § 192.452 already requires EFRDs to be installed to protect a HCA if the operator finds, through a risk assessment, that an HCA is threatened. MAWUC commented that EFRDs should be required if they can limit a spill. Likewise, NSB supported the use of EFRDs for HCAs. Response PHMSA does not propose to make any changes to the regulations concerning the use of EFRDs at this time. PHMSA will be studying this issue and may make proposals concerning this topic in a later rulemaking. Determining the Applicability of New Valve Location Requirements In the ANPRM, PHMSA asked for public comment on how the agency should apply any new valve location requirements that are developed for hazardous liquid pipelines. Comments The trade association, API–AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, indicated that valve spacing requirements should not be changed, and that delineating new construction for any type of grandfathering purpose would be difficult and confusing. Requiring retrofitting of existing lines to meet any E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules type of new requirement would be expensive for industry, create environmental impacts, potential construction accidents, and may cause interruption of service. The regulatory association, NAPSR, suggested that exemptions to new valve location requirements should be based on the consequence of failure. Particular attention should be paid to spills into water as even a small spill can create a large problem. Two government/municipalities commented. MAWUC indicated that there should be no waivers for valve spacing in HCAs due to the importance and interconnectivity of water supplies. NSB recommended that any new valve locations or remote actuation regulation be applied to new pipelines or existing pipelines that are repaired. Response PHMSA will continue to study valve spacing and automatic valve placement and may address these issues in a future rulemaking. E. Repair Criteria Outside of HCAs asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Repair Criteria The ANPRM asked for public comment on whether to extend the IM repair criteria in § 195.452(h) to pipeline segments that are not located in HCAs. Specifically, the ANPRM asked ‘‘Whether the IM repair criteria should apply to anomalous conditions discovered in areas outside of HCAs; whether the application of the IM repair criteria to non-HCA areas should be tiered on the basis of risk; what schedule should be applied to the repair of anomalous conditions discovered in non-HCA areas; whether standards should be specified for the accuracy and tolerance of inline inspection (ILI) tools; and whether additional standards should be established for performing ILI inspections with ‘‘smart pigs’’. As discussed below, PHMSA is proposing to modify the provisions for making pipeline repairs. Additional conservatism will be incorporated into the existing IM repair criteria and an adjusted schedule for making immediate and non-immediate repairs will be established to provide greater uniformity. These criteria will also be made applicable to all pipelines, with an extended timeframe for making repairs outside of HCAs. Application of IM Repair Criteria to Anomalous Conditions Discovered Outside of HCAs In the ANPRM, PHMSA asked for comment on whether the IM repair criteria should apply to anomalous VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 conditions discovered in areas outside of HCAs. Comments API–AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, stated that the repair criteria in or outside of HCAs should be the same. Likewise, the citizens’ groups TWS and AKW echoed the comments of API– AOPL and further recommended that a phased-in time period should be utilized. NSB commented that anomalous conditions found during inspection in non-HCA areas should trigger expedited repair times. Response Section 195.452(h) specifies the actions that an operator must take to address integrity issues on hazardous liquid pipelines that could affect an HCA in the event of a leak or failure. Those actions include initiating temporary and long-term pressure reductions and evaluating and remediating certain anomalous conditions (e.g., metal loss, dents, corrosion, cracks, gouges, grooves, and other any condition that could impair the integrity of the pipelines). Depending on the severity of the condition, such actions must be taken immediately, within 60 days, or within 180 days of the date of discovery. Section 5 of the Pipeline Safety Act of 2011 requires the Secretary to perform an evaluation to determine if the IM requirements should be extended outside of and to submit a report to Congress with the result of that review. The Secretary is authorized to collect data for purposes of completing the evaluation and report to Congress. Section 5 also prohibits the issuance of any final regulations that would expand the IM requirements during a subsequent Congressional review period, subject to a savings clause that permits such action if a condition poses a risk to public safety, property, or the environment or is an imminent hazard and the regulations in question will address that risk or imminent hazard. PHMSA is proposing to make certain modifications to the IM repair criteria and to establish similar repair criteria for pipeline segments that are not located in HCAs. Specifically, the repair criteria in § 195.452(h) would be amended to: • Categorize bottom-side dents with stress risers 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 PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 61631 • Establish a new, consolidated 270day repair category. PHMSA is also proposing to adopt new requirements in § 195.422 that would: Apply the criteria in the immediate repair category in § 195.452(h) and Establish an 18-month repair category for hazardous liquid pipelines that are not subject to the IM requirements. These changes will ensure that immediate action is taken to remediate anomalies that present an imminent threat to the integrity of hazardous liquid pipelines in all locations. Many anomalies that would not qualify as immediate repairs under the current criteria will meet that requirement as a result of the additional conservatism that will be incorporated into the burst pressure calculations. The new timeframes for performing other repairs will allow operators to remediate those conditions in a timely manner while allocating resources to those areas that present a higher risk of harm to the public, property, and the environment. Use of a Tiered, Risk-Based Approach for Repairing Anomalous Conditions Discovered Outside of HCAs In the ANPRM, PHMSA asked for comment on whether the application of the IM repair criteria to non-HCA areas should be tiered on the basis of risk. Comments API–AOPL, LMOGA, TPA, TxOGA, and TransCanada Keystone commented that PHMSA should not impose any sort of tiering to repair criteria because that is already inherent to the IM program. Scheduling flexibility would minimize disruption to the affected public, as well as the overall environmental impact, by preventing multiple excavation work on a given property. Requiring additional risk tiering of anomalies would not reduce safety risks to the public. NAPSR, in contrast, commented that tiering should be utilized for repair criteria inside or outside of HCAs. NSB also indicated that risk tiering should be used. MAWUC supported risk tiering based on preselected criteria for HCAs. Response As previously discussed, PHMSA is proposing to apply new repair criteria for anomalous conditions discovered on hazardous liquid pipelines that are not located in HCAs. PHMSA is also proposing to establish two timeframes for performing those repairs: immediate repair conditions and 18-month repair conditions. If adopted as proposed, these changes will ensure the prompt remediation of anomalous conditions on all hazardous liquid pipeline segments, while allowing operators to allocate E:\FR\FM\13OCP3.SGM 13OCP3 61632 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules their resources to those areas that present a higher risk of harm to the public, property, and the environment. Updating of Dent With Metal Loss Repair Criteria Section 195.452(h) contains the criteria for repairing dents with metal loss on hazardous liquid pipeline segments that could affect an HCA in the event of a leak or failure. PHMSA asked for comment on whether advances in ILI tool capability justified an update in the dent-with-metal-loss repair criteria. Comments API–AOPL, LMOGA, TxOGA, and TransCanada Keystone indicated that the anticipated update to API 1160 will contain proposals to update the dentwith-metal-loss repair criterion. API– AOPL intends to support these proposals with data resulting from analyses of member company’s experience measuring and characterizing metal loss in dents. NAPSR encouraged PHMSA not to make the current standards less stringent even for dents without metal loss, citing a recent bottom side dent less than 6 inches that failed. NAPSR recommended strengthening the repair criteria for bottom-side dents in areas of heavy traffic or near swamps/bogs or in clay soils. Response As previously discussed, PHMSA is proposing to categorize bottom-side dents with stress risers as an immediate repair condition and to require immediate repairs when calculated burst pressure is less than 1.1 times MOP. These changes should ensure the prompt and effective remediation of anomalous conditions on all pipeline segments. With respect to API 1160, PHMSA will consider incorporating the 2013 edition in a future rulemaking. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Adoption of Explicit Standards To Account for Accuracy of ILI Tools PHMSA requested comment on whether to adopt an explicit standard to account for the accuracy of ILI tools when comparing ILI data with repair criteria. Comments API–AOPL supports PHMSA’s adoption of API 1163, the ‘‘In-Line Inspection Systems Qualification Standard’’. That standard includes a System Results Verification section, which describes methods to verify that the reported inspection results meet, or are within, the performance specification for the pipeline being VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 inspected. That standard also requires that inconsistencies uncovered during the process validation be evaluated and resolved. NAPSR supports the adoption of a standard because the IM process already is considering tool accuracy during the selection process and suggests revising the regulations to provide minimum standards of expected accuracy. Response In reviewing IM inspection data, PHMSA discovered that some operators were not considering the accuracy (i.e., tolerance) of ILI tools when evaluating the results of the tool assessments. As a result, random variation within the recorded data led to both overcalls (i.e., an anomaly was identified to be more extreme than it actually was) and under calls. Over calls are conservative, resulting in repair of some anomalies that might not actually meet repair criteria. Under calls are not and can result in anomalies that exceed specified repair criteria going unremediated. Based on our review of inspection data, PHMSA has concluded that operators should be explicitly required to consider the accuracy of their ILI tools. Specifically, under the proposed amendment to § 195.452(c)(1)(i) and the new provisions in § 195.416, operators will be required to consider tool tolerance and other uncertainties in evaluating ILI results for all hazardous liquid pipeline segments. Tool accuracy should include excavation findings and usage of unity plots of inline tool and excavation findings. When combined with the proposed changes to the repair criteria, the proposed tool tolerance requirement will ensure the prompt detection and remediation of anomalous conditions on all hazardous liquid pipelines. With respect to API 1163, as of January 2013, PHMSA is required by section 24 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 not to incorporate any consensus standards that are not available to the public, for free, on an internet Web site. PHMSA has sought a solution to this issue and as a result, all incorporated by reference standards in the pipeline safety regulations would be available for viewing to the public for free. Additional Quality Control Standards for ILI Tools, Assessments, and Data Review In the ANPRM, PHMSA asked if additional quality control standards are needed for conducting ILIs using smart pigs, the qualification of persons interpreting ILI data, the review of ILI PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 results, and the quality and accuracy of ILI tool performance. Comments API–AOPL, LMOGA, TxOGA, and TransCanada Keystone commented that PHMSA should adopt API 1163 and American Society of Nondestructive Testing ILI PQ. These commenters stated that a certification program for analyzing ILI data would not add value to pipeline operators’ IM programs, as operator experience has shown that these types of programs do not adequately reflect the highly technical nature of, and the intimate knowledge and experience of personnel practicing, IM programs. According to the commenters, there is no evidence that the current requirements and industry standards are leaving the public or environment at risk. NAPSR indicated that if there is data to show this is an issue, PHMSA should adopt a standard. Additionally, a state could impose a more stringent standard based on prior experience. Both the NSB and MAWUC supported adoption of standards for ILI use. Response As noted in the response to the previous question, PHMSA is proposing to require operators to consider tool tolerance and other uncertainties in evaluating ILI results in complying with the IM requirements of § 195.452 and the proposed assessment requirement in § 195.416. PHMSA believes that this requirement and the proposed changes to the repair criteria will ensure the prompt detection and remediation of anomalous conditions (e.g., metal loss, dents, corrosion, cracks, gouges, grooves) that could adversely affect the safe operation of a pipeline. PHMSA is proposing by a separate rulemaking via incorporation by reference available industry consensus standards for performing assessments of pipelines using ILI tools, internal corrosion direct assessment, and stress corrosion cracking direct assessment. F. Stress Corrosion Cracking In the October 2010 ANPRM, PHMSA asked for public comment on whether to adopt additional safety standards for stress corrosion cracking (SCC). SCC is cracking induced from the combined influence of tensile stress and a corrosive medium. Sections 195.553 and 195.588 and Appendix C of the Hazardous Liquid Pipeline Safety Standards contain provisions for the direct assessment of SCC, but do not include comprehensive requirements for preventing, detecting, and remediating that condition. E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules Specifically, PHMSA asked in the ANPRM whether: • Any existing industry standards for preventing, detecting, and remediating SCC should be incorporated by reference; • Any data or statistics are available on the effectiveness of these industry standards; • Any data or statistics are available on the effectiveness of SCC detection tools and methodologies; • Any tools or methods are available for detecting SCC associated with longitudinal pipe seams; • An SCC threat analysis should be conducted for all pipeline segments; • Any particular integrity assessment methods should be used when SCC is a credible threat; and • Operators should be required to perform a periodic analysis of the effectiveness of their corrosion management programs. Adoption of NACE Standard for Stress Corrosion Cracking Direct Assessment Methodology or Other Industry Standards In the ANPRM, PHMSA asked for comment on whether the agency should incorporate any consensus industry standards for assessing SCC, including the NACE International (NACE) SP0204–2008 (formerly RP0204), Stress Corrosion Cracking (SCC) Direct Assessment Methodology. https:// www.nace.org/uploadedFiles/ Committees/SP020408.pdf (last accessed December 12, 2013) (stating that SP0204–2008 ‘‘provides guidance for managing SCC by selecting potential pipeline segments, selecting dig sites within those segments, inspecting the pipe and collecting and analyzing data during the dig, establishing a mitigation program, defining the reevaluation interval, and evaluating the effectiveness of the SCC [direct assessment] process.’’). asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Comments API–AOPL, TransCanada Keystone, TxOGA, and LMOGA stated that NACE SP0204–2008 provides an effective framework for the application of direct assessment, but does not sufficiently address other assessment methods, including ILI and hydrostatic testing. These commenters were also not aware of any industry statistics that directly correlate the application of that standard to the SCC detection or failure rate. These commenters stated the most appropriate standard for SCC assessment of hazardous liquid pipelines is the soon-to-be-released version of API Standard 1160, Managing VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 System Integrity for Hazardous Liquid Pipelines. Another trade association, TPA, stated that ‘‘because [the NACE Standard] was just finished in 2008, PHMSA should wait at least 2–3 years more before attempting to assess the desirability of incorporating that standard into the regulations.’’ One regulatory association, MAWUC, commented that PHMSA should adopt standards that address direct assessment, prevention, and remediation of SCC. The municipality/ government entity, NSB, offered a similar comment. Response The commenters did not indicate that NACE SP0204–2008 would address the full lifecycle of SCC safety issues. Moreover, none of the commenters identified any other industry standards that would be appropriate for adoption at this time. PHMSA recognizes that SCC is an important safety concern, but does not believe that further action can be taken based on the information available in this proceeding. PHMSA is establishing a team of experts to study this issue and will be holding a public forum on the development of SCC standards. Once that process is complete, PHMSA will consider whether to establish new safety standards for SCC. With respect to NACE SP0204–2008 PHMSA is proposing this standard by a separate rulemaking via incorporation by reference. Identification of Standards and Practices for Prevention, Detection, Assessment and Remediation of SCC PHMSA asked the public to identify any other standards and practices for the prevention, detection, assessment, and remediation of SCC. Comments API–AOPL, LMOGA, and TxOGA indicated that there are several good standards that address SCC, including API 1160, ASME STP–PT–011, Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas, and the Canadian Energy Pipeline Association (CEPA) Stress Corrosion Cracking Recommended Practices (CEPA SCC RP), but acknowledged that all of these standards have weaknesses. The trade association, CEPA, also stated that the 2008 ASME STP–PT–011 should be considered. While written for gas pipelines, CEPA stated that this standard could be adapted to hazardous liquids. PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 61633 Response PHMSA appreciates the information provided by the commenters. PHMSA will be studying the SCC issue and will consider incorporating by reference suggested standards in future rulemakings. Implementation of Canadian Energy Pipeline Association RP on SCC CEPA is an organization that represents Canada’s transmission pipeline companies. In 1997, CEPA developed its SCC Recommended Practice (RP) in response to a public inquiry by National Energy Board of Canada. In 2007, CEPA released an updated version of its SCC RP, https:// www.cepa.com/wp-content/uploads/ 2011/06/Stress-Corrosion-CrackingRecommended-Practices-2007.pdf. In the ANPRM, PHSMA asked for comment on the experience of operators in implementing CEPA’s SCC RP. Comments API–AOPL, LMOGA, TxOGA, and TransCanada Keystone commented that the CEPA SCC RP provides the most thorough overview of the various assessment techniques, but is limited to near neutral SCC in terms of causal considerations. These commenters also stated that there are no industry statistics on the application of the CEPA RP SCC. CEPA and API–AOPL both indicated that companies continue to use the CEPA SCC RP as a guideline, but that there are no statistics on its use. Response PHMSA appreciates the comments provided on the use of the CEPA SCC RP and will consider that standard in its study of comprehensive safety requirements for SCC and in future rulemakings. Effectiveness of SCC Detection Tools and Methods PHMSA requested comment as to the effectiveness of current SCC detection tools and methods. Comments API–AOPL, supported by LMOGA, TxOGA, and TransCanada Keystone, stated that there are no industry statistics that directly correlate the application of the CEPA RP to the SCC detection or failure rate, but that the National Energy Board of Canada has noted the effectiveness of the CEPA RP for managing SCC. API–AOPL also stated the planned revisions of API 1160 and 1163 will address the current gaps regarding SCC in the standards and recommended practices relevant to liquid pipelines. One citizens’ group, E:\FR\FM\13OCP3.SGM 13OCP3 61634 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules TWS, mentioned that gathering lines do not require corrosion prevention and that this should be required. Response PHMSA appreciates the comments provided on the effectiveness of SCC detection tools and methods and will be considering that information in evaluating comprehensive safety requirements for SCC and consider incorporating in future rulemakings. IV. 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 part 195, including gathering lines that cross waterways used for commercial navigation as well as certain onshore gathering lines (i.e., those that are located in a non-rural area, that meet the definition of a regulated onshore gathering line, or that are located in an inlet of the Gulf of Mexico). PHMSA has determined that additional information about unregulated gathering lines is needed to fulfill its statutory obligations. Accordingly, the NPRM extend the reporting requirements in subpart B of part 195 to all gathering lines (whether regulated, unregulated, onshore, or offshore) by adding a new paragraph (a)(5) to § 195.1. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS § 195.2 Definitions Section 195.2 provides definitions for various terms used throughout part 195. On August 10, 2007, (72 FR 45002; Docket number PHMSA–2007–28136) PHMSA published a policy statement and request for comment on the transportation of ethanol, ethanol blends, and other biofuels by pipeline. PHMSA noted in the policy statement that the demand for biofuels was projected to increase in the future as a result 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 now proposing to modify its definition of hazardous liquid in § 195.2. Such a change would make clear that the transportation of biofuel by pipeline is subject to the requirements of 49 CFR part 195. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 PHMSA is also proposing to add a new definition of ‘‘Significant Stress Corrosion Cracking.’’ This new definition will provide criteria for determining when a probable crack defect in a pipeline segment must be excavated and repaired. 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. § 195.11 What is a regulated rural gathering line and what requirements apply? Section 195.11 defines and establishes the requirements that are applicable to regulated rural gathering lines. PHMSA has determined that these lines should be subject to the new requirements in the NPRM for the performance of periodic pipeline assessments and pipeline remediation and for establishing leak detection systems. Consequently, the NPRM would amend § 195.11 by adding paragraphs (b)(12) and (13) to ensure that these requirements are applicable to regulated rural gathering lines. Section 195.401 prescribes general requirements for the operation and maintenance of hazardous liquid pipelines. PHMSA is proposing to modify the pipeline repair requirements in § 195.401(b). Paragraph (b)(1) will be modified to reference the new timeframes in § 195.422 for performing non-IM repairs. The requirements in paragraph (b)(2) for IM repairs will be retained without change. A new paragraph (b)(3) will be 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, including those covered by the timeframes specified in §§ 195.422(d) and (e) and 195.452(h). § 195.13 What requirements apply to pipelines transporting hazardous liquids by gravity? Section 195.13 will be added which subjects gravity lines to the same reporting requirements in subpart B of part 195 as other hazardous liquid pipelines. PHMSA has determined that additional information about gravity lines is needed to fulfill its statutory obligations. § 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, the NPRM would repeal 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 would be re-organized without altering the existing substantive requirements. § 195.134 Leak Detection Section 195.134 contains the design requirements for computational pipeline monitoring leak detection systems. The NPRM would restructure the existing requirements into paragraphs (a) and (b) and add a new provision in paragraph (c) to ensure that all newly constructed PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 § 195.401 General Requirements § 195.414 Inspections of Pipelines in Areas Affected by Extreme Weather, a Natural Disaster, and Other Similar Events Extreme weather, natural disasters and other similar events can affect the safe operation of a pipeline. Accordingly, the NPRM would establish a new regulation in § 195.414 that would require operators to perform inspections after these events and to take appropriate remedial actions. § 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 that is needed to promptly detect and remediate conditions that could affect the safe operation of pipelines in all areas. Accordingly, the NPRM would establish a new regulation in § 195.416 that requires operators to perform an assessment of pipelines that are not already subject to the IM requirements at least once every 10 years. The regulation would require that these assessments be performed with an ILI tool, unless an operator demonstrates and provides 90-days prior notice that a pipeline is not capable of accommodating such a device and that an alternative method will provide a substantially equivalent understanding of its condition. E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules The regulation would also require 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 new requirements in § 195.422 of the NPRM; and that all relevant information about the pipeline be considering in complying with the requirements of § 195.416. § 195.422 Pipeline Remediation Section 195.422 contains the requirements for performing pipeline repairs. PHMSA has determined that new criteria should be established for remediating conditions that affect the safe operation of a pipeline. The NPRM would add a new paragraph (a) specifying that the provisions in the regulation are applicable to pipelines that are not subject to the IM requirements in § 195.452 (e.g., not in HCAs). Paragraphs (b) and (c) would contain the existing requirements in the regulation, including the general duty clause for ensuring public safety and the provision noting the applicability of the design and construction requirements to piping and equipment used in performing pipeline repairs. Paragraph (d) would establish a new remediation schedule based on the analogous provisions in the IM requirements for performing immediate and 18-month repairs, and paragraph (e) would contain a residual provision for remediating all other conditions. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS § 195.444 Leak Detection Section 195.444 contains the operation and maintenance requirements for Computational Pipeline Monitoring leak detection systems. PHMSA is proposing that all pipelines should have leak detection systems. Therefore, the NPRM would reorganize the existing requirements of the regulation into paragraphs (a) and (c), and add a new general provision in paragraph (b) that would require operators to have leak detection systems on all 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 NPRM would clarify the applicability of the deadlines in paragraph (b) for the development of a written program for new pipelines, regulated rural gathering lines, and low-stress pipelines in rural areas. Paragraph (c)(1)(i)(A) would also be amended to ensure that operators consider uncertainty in tool tolerance in reviewing the results of ILI assessments. Paragraph (d) would be amended to eliminate obsolete deadlines for performing baseline assessments and to clarify the requirements for newlyidentified HCAs. Paragraph (e)(1)(vii) is amended to include local environmental factors that might affect pipeline integrity. Paragraph (g) would be amended to expand upon the factors and criteria that operators must consider in performing the information analysis that is required in periodically evaluating the integrity of covered pipeline segments. Paragraph (h)(1) would also be amended by modifying the criteria, and establishing a new, consolidated timeframe, for performing immediate and 270-day pipeline repairs based on the information obtained as a result of ILI assessments or through an information analysis of a covered segment. PHMSA is also proposing to amend the existing ‘‘discovery of condition’’ language in the pipeline safety regulations. The revised § 195.452(h)(2) will require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators must notify PHMSA and provide an expected date when adequate information will become available. Paragraphs 195.452(h)(4)(i)(E) and (F) are also added to address issues of significant stress corrosion cracking and selective seam corrosion. PHMSA proposes further changes to § 195.452. These changes include paragraph (j) which would be 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) would also be added to require that all pipelines in 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 permit that accommodation or the existence of an emergency renders such an accommodation impracticable. Paragraph (n) would also require that pipelines in newly-identified HCAs after the 20-year period be made capable of accommodating ILIs within five years of the date of identification or before the performance of the baseline assessment, whichever is sooner. Finally, an explicit reference to seismicity will be 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). V. Regulatory Notices A. Executive Order 12866, Executive Order 13563, and DOT Regulatory Policies and Procedures Executive Orders 12866 and 13563 require agencies to regulate in the ‘‘most cost-effective manner,’’ to make a ‘‘reasoned determination that the benefits of the intended regulation justify its costs,’’ and to develop regulations that ‘‘impose the least burden on society.’’ This action has been determined to be significant under Executive Order 12866 and the Department of Transportation’s Regulatory Policies and Procedures. It has been reviewed by the Office of Management and Budget in accordance with Executive Order 13563 (Improving Regulation and Regulatory Review) and Executive Order 12866 (Regulatory Planning and Review) and is consistent with the requirements in both orders. In the regulatory analysis, we discuss the alternatives to the proposed requirements and, where possible, provide estimates of the benefits and costs for specific regulatory requirements in the eight areas. The regulatory analysis provides PHMSA’s best estimate of the impact of the separate requirements. The chart below summarizes the cost/benefit analysis: ANNUALIZED COSTS AND BENEFITS BY REQUIREMENT AREA DISCOUNTED AT 7 PERCENT Requirement area Costs Benefits 1. Extend certain reporting requirements to all hazardous liquid (HL) gravity lines. $900 .............................................. Benefits not quantified, but expected to justify costs. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 61635 E:\FR\FM\13OCP3.SGM Net benefits Expected to be positive. 13OCP3 61636 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules ANNUALIZED COSTS AND BENEFITS BY REQUIREMENT AREA DISCOUNTED AT 7 PERCENT—Continued Costs Benefits 2. Extend certain reporting requirements to all hazardous liquid (HL) gathering lines. 3. Require inspections of pipelines in areas affected by extreme weather, natural disasters, and other similar events, as well as appropriate remedial action if a condition that could adversely affect the safe operation of a pipeline is discovered. 4. Require periodic assessments of pipelines that are not already covered under the IM program requirements using an in-line inspection tool (or demonstrate to the satisfaction of PHMSA that the pipeline is not capable of using this tool). 5. Require use of leak detection systems (LDS) on new HL pipelines located in non-HCAs to mitigate the effects of failures that occur outside of HCAs. 6. Modify the IM repair criteria, both by expanding the list of conditions that require immediate remediation, consolidating the timeframes for remediating all other conditions, and making explicit deadlines for repairs on non-IM pipeline. 7. Increase the use of inline inspection (ILI) tools by requiring that any pipeline that could affect an HCA be capable of accommodating these devices within 20 years, unless its basic construction will not permit that accommodation. 8. Clarify and resolve inconsistencies regarding deadlines, and information analyses for IM Plans t. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS Requirement area 23,300 ........................................... Benefits not quantified but expected to justify the costs. Expected to be positive. 1.5 million ..................................... 3.5 to 10.4 million ......................... 2.0 to 8.9 million 16.7 million ................................... 17.7 million ................................... Range 9.4–26.0 million ................. 1 million Range (–)7.3–9.3 million Expected to be positive even at the low end of the benefit range if unquantified benefits are included. Not quantified but expected to be minimal. Not quantified, but expected to justify the minimal costs. Not quanitified, but positive qualitative benefits. Not quantified, but expected to be minimal. Not quantified, but expected to justify the minimal costs. Not quantified, but expected to be minimal. 1.0 million ..................................... 12.2 million ................................... 11.2 million 3.2 million ..................................... 10.0 million ................................... 6.8 million. 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 are in excess of the cost. PHMSA seeks comment on the Preliminary Regulatory Evaluation, its approach, and the accuracy of its estimates of costs and benefits. A copy of the Preliminary Regulatory evaluation has been placed in the docket. B. Executive Order 13132: Federalism This NPRM has been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (‘‘Federalism’’). This NPRM does not propose any regulation that has substantial direct effects on the states, the relationship between the national VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 government and the states, or the distribution of power and responsibilities among the various levels of government. It does not propose 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. Nevertheless, PHMSA has and will continue to consult extensively with state regulators including NAPSR to ensure that any state concerns are taken into account. C. 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 PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 Net benefits 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 E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules 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 potential economic impact on small entities. The screening analysis is available in the docket for the rulemaking. PHMSA estimates that the proposed rule would impact fewer than 100 small hazardous liquid pipeline operators, and that the majority of these operators would experience annual compliance costs that represent less than 1% of annual revenues. Less than 20 small operators would incur annual compliance costs that represent greater than 1% of annual revenues; less than 10 would incur annual compliance costs of greater than 3% of annual revenues; and none would incur compliance costs of more than 20% of annual revenues. PHMSA determined that these impacts results do not represent a significant impact for a substantial number of small hazardous liquid pipeline operators. Therefore, I certify that this action, if promulgated, will not have a significant economic impact on a substantial number of small entities. D. National Environmental Policy Act PHMSA analyzed this NPRM 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 preliminarily determined that this action will not significantly affect the quality of the human environment. A preliminary environmental assessment of this rulemaking is available in the docket and PHMSA invites comment on environmental impacts of this rule, if any. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS E. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This NPRM has been analyzed in accordance with the principles and criteria contained in Executive Order 13175 (‘‘Consultation and Coordination with Indian Tribal Governments’’). Because this NPRM 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. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 F. Paperwork Reduction Act 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 that the proposals in this rulemaking will add a new information collection and impact several approved information collections titled: ‘‘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 and; ‘‘Pipeline Safety: New Reporting Requirements for Hazardous Liquid Pipeline Operators: Hazardous Liquid Annual Report’’ identified under OMB Control Number 2137–0614. Based on the proposals in this rulemaking, PHMSA will submit an information collection revision request to OMB for approval based on the requirements in this NPRM. The information collection is contained in the pipeline safety regulations, 49 CFR parts 190 through 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: April 30, 2014. 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. Additional information is PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 61637 also obtained concerning the characteristics of an operator’s pipeline system. As a result of this NPRM, 5 gravity line operators and 23 gathering line operators would be required to submit accident reports to PHMSA on occasion. These 28 additional operators will also be required to keep mandated records. This information collection is being revised to account for the additional burden that will be incurred by these newly regulated entities. Operators currently submitting annual reports will not be otherwise impacted by this NPRM. Affected Public: Owners and operators of Hazardous Liquid Pipelines. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 881. Total Annual Burden Hours: 55,455. 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: May 31, 2014. Abstract: 49 U.S.C. 60102 requires each operator of a pipeline facility (except master meter operators) to submit to 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 hazards to life, property or the environment. As a result of this NPRM, approximately 5 gravity line operators and 23 gathering line operators will be required to adhere to the Safety-Related Condition reporting requirements. 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: 178. Total Annual Burden Hours: 1,020. Frequency of Collection: On occasion. 3. Title: Integrity Management in High Consequence Areas for Operators of Hazardous Liquid Pipelines. OMB Control Number: 2137–0605. Current Expiration Date: November 30, 2016. 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 E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS 61638 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules remedial preventive and mitigative actions. As a result of this NPRM, operators not currently under IM plans will be required to adhere to the repair criteria currently required for operators who are under IM plans. In conjunction with this requirement, operators who are not able to make the necessary repairs within 180 days of the infraction will be required to notify PHMSA in writing. PHMSA estimates that only 1% of repair reports will require more than 180 days. Accordingly, PHMSA approximates that 75 reports per year will fall within this category. Affected Public: Owners and operators of Hazardous Liquid Pipelines. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 278. Total Annual Burden Hours: 325,508. Frequency of Collection: Annually. 4. Title: Pipeline Safety: New Reporting Requirements for Hazardous Liquid Pipeline Operators: Hazardous Liquid Annual Report. OMB Control Number: 2137–0614. Current Expiration Date: April 30, 2014. 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 compile a national pipeline inventory, identify safety problems, and target inspections. As a result of this NPRM, approximately 5 gravity line operators and 23 gathering line operators will be required to submit annual reports to PHMSA. This information collection is being revised to account for the additional burden that will be incurred. 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: 8,567. Frequency of Collection: Annually. 5. Title: Pipeline Safety: Notification Requirements for Hazardous Liquid Operators. OMB Control Number: New OMB Control No. Current Expiration Date: TBD. Abstract: Owners and operators of non-High Consequence Area hazardous liquid pipelines will be required to provide PHMSA with notifications when unable to assess their pipeline via an in-line inspection. Affected Public: Owners and operators of Hazardous Liquid Pipelines. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 Annual Reporting and Recordkeeping Burden: Total Annual Responses: 10. Total Annual Burden Hours: 10. Frequency of Collection: On occasion. Requests for copies of these information collections should be directed to Angela Dow or Cameron Satterthwaite, Office of Pipeline Safety (PHP–30), Pipeline Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE., Washington, DC 20590–0001, Telephone (202) 366–4595. G. 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. H. 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 proposes to amend 49 CFR part 195 as follows: under paragraphs (a)(1), (2), (3) or (4) of this section. * * * * * ■ 3. In section 195.2, the definition for ‘‘Hazardous liquid’’ is revised and a definition of ‘‘Significant stress corrosion cracking’’ is added in alphabetical order to read as follows: § 195.2 Definitions. * * * * * Hazardous liquid means petroleum, petroleum products, anhydrous ammonia or non-petroleum fuel, including biofuel that is flammable, toxic, or corrosive or would be harmful to the environment if released in significant quantities. * * * * * Significant stress corrosion cracking means a stress corrosion cracking (SCC) cluster in which the deepest crack, in a series of interacting cracks, is greater than 10% of the wall thickness and the total interacting length of the cracks is equal to or greater than 75% of the critical length of a 50% through-wall flaw that would fail at a stress level of 110% of SMYS. * * * * * ■ 4. In section 195.11, add paragraphs (b)(12) and (13) to read as follows: § 195.11 What is a regulated rural gathering line and what requirements apply? * * * * * (b) * * * (12) Perform pipeline assessments and remediation as required under §§ 195.416 and 195.422. (13) Establish a leak detection system in compliance with §§ 195.134 and 195.444. * * * * * ■ 5. Section 195.13 is added to subpart A to read as follows: PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE § 195.13 What reporting requirements apply to pipelines transporting hazardous liquids by gravity? 1. The authority citation for part 195 is revised to read as follows: (a) Scope. This section applies to pipelines transporting hazardous liquids by gravity as of [effective date of the final rule]. (b) Annual, accident and safety related reporting. Comply with the reporting requirements in subpart B of this part by [date 6 months after effective date of the final rule]. ■ 6. Section 195.120 is revised to read as follows: ■ Authority: 49 U.S.C. 5103, 60101, 60102, 60104, 60108, 60109, 60116, 60118, 60131, 60131, 60137, and 49 CFR 1.97. 2. In § 195.1, paragraph (a)(5) is added, paragraph (b)(2) is removed, and paragraphs (b)(3) through (10) are redesignated as (b)(2) through (9). The addition reads 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 PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 § 195.120 devices. Passage of internal inspection (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 E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules pipe, valve, fitting or other line component is replaced must be designed and constructed to accommodate the passage of instrumented internal inspection devices. (b) Exceptions. This section does not apply to: (1) Manifolds; (2) Station piping such as at pump stations, meter stations, or pressure reducing stations; (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 main 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) 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 the petition is denied, 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. ■ 7. Section 195.134 is revised to read as follow: asabaliauskas on DSK5VPTVN1PROD with PROPOSALS § 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. Each pipeline must have a system for detecting leaks that complies with the requirements in § 195.444. (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. ■ 8. In § 195.401, the introductory text of paragraph (b) and paragraph (b)(1) are VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 revised and paragraph (b)(3) is added to read as follows. § 195.401 General requirements. * * * * * (b) An operator must make repairs on its pipeline system according to the following requirements: (1) Non integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of a pipeline not covered under § 195.452, it must correct the condition as prescribed in § 195.422. 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. * * * * * (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. * * * * * ■ 9. Section 195.414 is added to read as follows: § 195.414 Inspections of pipelines in areas affected by extreme weather, a natural disaster, and other similar events. (a) General. Following an extreme weather event such as a hurricane or flood, an earthquake, a natural disaster, or other similar event, an operator must inspect all potentially affected pipeline facilities to ensure that no conditions exist 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 inspection required under paragraph (a) of this section. (c) Time period. The inspection required under paragraph (a) of this section must occur within 72 hours after the cessation of the event, or as soon as 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. (d) Remedial action. An operator must take 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; PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 61639 (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. ■ 10. Section 195.416 is added to read as follows: § 195.416 Pipeline assessments. (a) Scope. This section applies to pipelines that are not subject to the integrity management requirements in § 195.452. (b) General. An operator must perform an assessment of a pipeline at least once every 10 years, or as otherwise necessary to ensure public safety. (c) Method. The assessment required under paragraph (b) of this section must be performed with an in-line inspection tool or tools capable of detecting corrosion and deformation anomalies, including dents, cracks, gouges, and grooves, unless an operator: (i) Demonstrates that the pipeline is not capable of accommodating an inline inspection tool; and that the use of an alternative assessment method will provide a substantially equivalent understanding of the condition of the pipeline; and (ii) Notifies the Office of Pipeline Safety (OPS) 90 days before conducting the assessment by: (A) Sending the notification, along with the information required to demonstrate compliance with paragraph (c)(i) of this section, to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590; or (B) Sending the notification, along with the information required to demonstrate compliance with paragraph (c)(i) of this section, to the Information Resources Manager by facsimile to (202) 366–7128. (d) 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. Uncertainties in any reported results (including tool tolerance) must be considered as part of that analysis. (e) Discovery of condition. For purposes of § 195.422, discovery of a E:\FR\FM\13OCP3.SGM 13OCP3 61640 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules condition occurs when an operator has adequate information to determine that a condition exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition and make the determination required under paragraph (d) of this section, unless 180days is impracticable as determined by PHMSA. (f) Remediation. An operator must comply with the requirements in § 195.422 if a condition that could adversely affect the safe operation of a pipeline is discovered in complying with paragraphs (d) and (e) of this section. (g) Consideration of information. An operator must consider all relevant information about a pipeline in complying with the requirements in paragraphs (a) through (f) of this section. ■ 11. Section 195.422 is revised to read as follows: asabaliauskas on DSK5VPTVN1PROD with PROPOSALS § 195.422 Pipeline remediation. (a) Scope. This section applies to pipelines that are not subject to the integrity management requirements in § 195.452. (b) General. Each operator must, in repairing its pipeline systems, ensure that the repairs are made in a safe manner and are made so as to prevent damage to persons, property, or the environment. (c) Replacement. An operator may not use any pipe, valve, or fitting, for replacement in repairing pipeline facilities, unless it is designed and constructed as required by this part. (d) Remediation schedule. An operator must complete the remediation of a condition according to the following schedule: (1) Immediate repair conditions. An operator must repair the following conditions immediately upon discovery: (i) Metal loss greater than 80% of nominal wall regardless of dimensions. (ii) A calculation of the remaining strength of the pipe shows a burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ ANSI B31G (‘‘Manual for Determining the Remaining Strength of Corroded Pipelines’’ (1991) or AGA Pipeline Research Committee Project PR–3–805 (‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe’’ (December 1989)) (incorporated by reference, see § 195.3. (iii) A dent located anywhere on the pipeline that has any indication of metal loss, cracking or a stress riser. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 (iv) A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth greater than 6% of the nominal pipe diameter. (v) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. (vi) Any indication of significant stress corrosion cracking (SCC). (vii) Any indication of selective seam weld corrosion (SSWC). (2) Until the remediation of a condition specified in paragraph (d)(1) of this section is complete, an operator must: (i) Reduce the operating pressure of the affected pipeline using the formula specified in paragraph 195.422(d)(3)(iv) or; (ii) Shutdown the affected pipeline. (3) 18-month repair conditions. An operator must repair the following conditions within 18 months of discovery: (i) A dent with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. (ii) A dent located on the top of the pipeline (above 4 and 8 o’clock position) with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12). (iii) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline’s diameter. (iv) A calculation of the remaining strength of the pipe at the anomaly shows a safe operating pressure that is less than the MOP at that location. Provided the safe operating pressure includes the internal design safety factors in § 195.106 in calculating the pipe anomaly safe operating pressure, suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (‘‘Manual for Determining the Remaining Strength of Corroded Pipelines’’ (1991)) or AGA Pipeline Research Committee Project PR–3–805 (‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe’’ (December 1989)) (incorporated by reference, see § 195.3). (v) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall. (vi) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld. PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 (vii) A potential crack indication that when excavated is determined to be a crack. (viii) Corrosion of or along a seam weld. (ix) A gouge or groove greater than 12.5% of nominal wall. (e) Other conditions. Unless another timeframe is specified in paragraph (d) of this section, an operator must take appropriate remedial action to correct any condition that could adversely affect the safe operation of a pipeline system within a reasonable time. ■ 12. Section 195.444 is revised to read as follows: § 195.444 Leak detection. (a) Scope. This section applies to each hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid). (b) General. A pipeline must have a system for detecting leaks. An operator must evaluate and modify, as necessary, the capability of its leak detection system to protect the public, property, and the environment. An operator’s evaluation must, at least, 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. ■ 13. In § 195.452: ■ a. Revise paragraphs (a), (b)(1), introductory text of paragraph (c)(1)(i), (c)(1)(i)(A), (d), (e)(1)(vii), (g), introductory text of (h)(1), (h)(2), and (h)(4); ■ b. Revise paragraph (i)(2)(viii) by removing the period at the end of the last sentence and adding in its place a ‘‘;’’ and add paragraph (i)(2)(ix); ■ c. Revise paragraphs (j)(1) and (2); ■ d. Add paragraph (n). The revisions and additions read as follows: § 195.452 Pipeline integrity management in high consequence areas. (a) Which pipelines are covered by this section? This section applies to each hazardous liquid pipeline and carbon dioxide pipeline that could affect a high consequence area, including any pipeline located in a high consequence area, unless the operator demonstrates that a worst case discharge from the pipeline could not affect the area. (Appendix C of this part provides E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules guidance on determining if a pipeline could affect a high consequence area.) Covered pipelines are categorized as follows: (1) Category 1 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to this part. (2) Category 2 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated less than 500 miles of pipeline subject to this part. (3) Category 3 includes pipelines constructed or converted after May 29, 2001, 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 first column of the following table not later than the date in the second column: 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. asabaliauskas on DSK5VPTVN1PROD with PROPOSALS * * * * * (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 unless it is impracticable, then use methods (B), (C) or (D) of this paragraph. The methods an operator selects to assess low frequency electric resistance welded pipe, or lap welded pipe, or 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 and of detecting corrosion and deformation anomalies. (A) Internal inspection tool or tools capable of detecting corrosion, and deformation anomalies including dents, cracks (pipe body and weld seams), gouges and grooves. 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 the pipeline begins operation. VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 (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 one 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 five years from the date the area is identified. * * * * * (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. This analysis must: (1) Integrate information and attributes about the pipeline which 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); (iv) Endpoints of segments that could affect high consequence areas (HCAs); (v) Hydrostatic test pressure including any test failures—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 § 195.569); (xvi) Stress corrosion cracking (SCC) and other cracking (pipe body or weld) PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 61641 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 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. 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 longterm integrity of the pipeline. An operator must comply with all other applicable requirements in this part in remediating a condition. * * * * * (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information to determine that a condition exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition and make the determination required, unless the operator can demonstrate that that 180-day is impracticable. If 180days is impracticable to make a E:\FR\FM\13OCP3.SGM 13OCP3 asabaliauskas on DSK5VPTVN1PROD with PROPOSALS 61642 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules 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. * * * * * (4) Special requirements for scheduling remediation—(i) Immediate repair conditions. An operator’s evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce the operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formulas in paragraph (h)(4)(i)(B) of this section, if applicable, or when the formulas in paragraph (h)(4)(i)(B) of this section are not applicable by using a pressure reduction determination in accordance with § 195.106 and the appropriate remaining pipe wall thickness, or if all of these are unknown a minimum 20 percent or greater operating pressure reduction must be implemented until the anomaly is repaired. If the formula is not applicable to the type of anomaly or would produce a higher operating pressure, an operator must use an alternative acceptable method to calculate a reduced operating pressure. An operator must treat the following conditions as immediate repair conditions: (A) Metal loss greater than 80% of nominal wall regardless of dimensions. (B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ ANSI B31G (‘‘Manual for Determining the Remaining Strength of Corroded Pipelines’’ (1991) or AGA Pipeline Research Committee Project PR–3–805 (‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe’’ (December 1989)) (incorporated by reference, see § 195.3). (C) A dent located anywhere on the pipeline that has any indication of metal loss, cracking or a stress riser. (D) A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth greater than 6% of the nominal pipe diameter. (E) Any indication of significant stress corrosion cracking (SCC). (F) Any indication of selective seam weld corrosion (SSWC) (G) An anomaly that in the judgment of the person designated by the operator VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 to evaluate the assessment results requires immediate action. (ii) 270-day conditions. Except for conditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the following within 270 days of discovery of the condition: (A) A dent with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. (B) A dent located on the top of the pipeline (above 4 and 8 o’clock position) with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12). (C) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline’s diameter. (D) A calculation of the remaining strength of the pipe at the anomaly shows a safe operating pressure that is less than MOP at that location. Provided the safe operating pressure includes the internal design safety factors in § 195.106 in calculating the pipe anomaly safe operating pressure, suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (‘‘Manual for Determining the Remaining Strength of Corroded Pipelines’’ (1991)) or AGA Pipeline Research Committee Project PR–3–805 (‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe’’ (December 1989)) (incorporated by reference, see § 195.3). (E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall. (F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld. (G) A potential crack indication that when excavated is determined to be a crack. (H) Corrosion of or along a longitudinal seam weld. (I) A gouge or groove greater than 12.5% of nominal wall. (iii) Other Conditions. In addition to the conditions listed in paragraphs (h)(4)(i) and (ii) of this section, an operator must evaluate any condition identified by an integrity assessment or information analysis that could impair the integrity of the pipeline, and as appropriate, schedule the condition for remediation. Appendix C of this part contains guidance concerning other conditions that an operator should evaluate. PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 (i) * * * (2) * * * (ix) Seismicity of the area. * * * * * (j) * * * (1) General. After completing the baseline integrity assessment, an operator must continue to assess the line pipe at specified intervals and periodically evaluate the integrity of each pipeline segment that could affect a high consequence area. (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 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 new risk factors should be considered, 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 under this paragraph no later than [date one year after effective date of the final rule]. * * * * * (n) Accommodation of 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 [date 20 years from effective date of the final rule]. (3) Newly-identified areas. If a pipeline could affect a newly-identified high consequence area (see paragraph (d)(3) of this section) after [date 20 years from effective date of the final rule], an operator must modify the pipeline to accommodate the passage of an instrumented internal inspection device within five 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 E:\FR\FM\13OCP3.SGM 13OCP3 Federal Register / Vol. 80, No. 197 / Tuesday, October 13, 2015 / Proposed Rules asabaliauskas on DSK5VPTVN1PROD with PROPOSALS the basic construction (i.e. length, diameter, operating pressure, or location) of a pipeline cannot be modified to accommodate the passage of an internal inspection device. (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 VerDate Sep<11>2014 21:35 Oct 09, 2015 Jkt 238001 an instrumented internal inspection device as a result of an emergency. Such a petition must be filed 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 one year after the date of the notice of the denial. PO 00000 Frm 00035 Fmt 4701 Sfmt 9990 61643 Issued in Washington, DC on October 1, 2015, under authority delegated in 49 CFR Part 1.97(a). Linda Daugherty, Deputy Associate Administrator for Field Operations. [FR Doc. 2015–25359 Filed 10–9–15; 8:45 am] BILLING CODE 4910–60–P E:\FR\FM\13OCP3.SGM 13OCP3

Agencies

[Federal Register Volume 80, Number 197 (Tuesday, October 13, 2015)]
[Proposed Rules]
[Pages 61609-61643]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-25359]



[[Page 61609]]

Vol. 80

Tuesday,

No. 197

October 13, 2015

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; Proposed Rule

Federal Register / Vol. 80 , No. 197 / Tuesday, October 13, 2015 / 
Proposed Rules

[[Page 61610]]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 195

[Docket No. PHMSA-2010-0229]
RIN 2137-AE66


Pipeline Safety: Safety of Hazardous Liquid Pipelines

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

ACTION: Notice of proposed rulemaking.

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SUMMARY: In recent years, there have been significant hazardous liquid 
pipeline accidents, most notably the 2010 crude oil spill near 
Marshall, Michigan, during which almost one million gallons of crude 
oil were spilled into the Kalamazoo River. In response to accident 
investigation findings, incident report data and trends, and 
stakeholder input, PHMSA published an Advance Notice of Proposed 
Rulemaking (ANPRM) in the Federal Register on October 18, 2010. The 
ANPRM solicited stakeholder and public input and comments on several 
aspects of hazardous liquid pipeline regulations being considered for 
revision or updating in order to address the lessons learned from the 
Marshall, Michigan accident and other pipeline safety issues. 
Subsequently, Congress enacted the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act that included several provisions that 
are relevant to the regulation of hazardous liquid pipelines. Shortly 
after the Pipeline Safety, Regulatory Certainty, and Job Creation Act 
was passed, the National Transportation Safety Board (NTSB) issued its 
accident investigation report on the Marshall, Michigan accident. In 
it, NTSB made additional recommendations regarding the need to revise 
and update hazardous liquid pipeline regulations.
    In response to these mandates, recommendations, lessons learned, 
and public input, PHMSA is proposing to make changes to the hazardous 
liquid pipeline safety regulations. PHMSA is proposing these changes 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 unsafe conditions, and 
mitigating the adverse effects of pipeline failures.

DATES: Persons interested in submitting written comments on this NPRM 
must do so by January 8, 2016. PHMSA will consider late filed comments 
so far as practicable.

ADDRESSES: You may submit comments identified by the docket number 
PHMSA-2010-0229 by any of the following methods:
    Federal eRulemaking Portal: https://www.regulations.gov. Follow the 
online instructions for submitting comments. Fax: 1-202-493-2251.
    Mail: Hand Delivery: U.S. DOT Docket Management System, West 
Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., 
Washington, DC 20590-0001, between 9 a.m. and 5 p.m., Monday through 
Friday, except federal holidays.
    Instructions: If you submit your comments by mail, submit two 
copies. To receive confirmation that PHMSA received your comments, 
include a self-addressed stamped postcard.

     Note:  Comments are posted without changes or edits to https://www.regulations.gov, including any personal information provided. 
There is a privacy statement published on https://www.regulations.gov.


FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366-
4571, by fax at 202-366-4566, or by mail at U.S. DOT, PHMSA, 1200 New 
Jersey Avenue SE., PHP-30, Washington, DC 20590-0001.

SUPPLEMENTARY INFORMATION: 
    Outline of this document:

I. Executive Summary
II. Background and NPRM Proposals
III. Analysis of Advance Notice of Proposed Rulemaking
    A. Scope of Part 195 and Existing Regulatory Exceptions
    B. Definition of High Consequence Area
    C. Leak Detection Equipment and Emergency Flow Restricting 
Devices
    D. Valve Spacing
    E. Repair Criteria Outside of High Consequence Areas
    F. Stress Corrosion Cracking
IV. Section by Section Analysis
V. Regulatory Notices and Proposed Changes to Regulatory Text

I. Executive Summary

    In recent years, there have been significant hazardous liquid 
pipeline accidents, most notably the 2010 crude oil spill near 
Marshall, Michigan, during which almost one million gallons of crude 
oil were spilled into the Kalamazoo River. In response to accident 
investigation findings, incident report data and trends, and 
stakeholder input, PHMSA published an ANPRM in the Federal Register on 
October 18, 2010, (75 FR 63774). The ANPRM solicited stakeholder and 
public input and comments on several aspects of hazardous liquid 
pipeline regulations being considered for revision or updating in order 
to address the lessons learned from the Marshall, Michigan accident and 
other pipeline safety issues.
    Subsequently, Congress enacted the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (The Act). 
That legislation included several provisions that are relevant to the 
regulation of hazardous liquid pipelines. Shortly after the Act was 
passed, NTSB issued its accident investigation report on the Marshall, 
Michigan accident. In it, NTSB made additional recommendations 
regarding the need to revise and update hazardous liquid pipeline 
regulations. Specifically, the NTSB issued recommendations P-12-03 and 
P-12-04 respectively, which addressed detection of pipeline cracks and 
``discovery of condition''. 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 the Pipeline and 
Hazardous Materials Safety Administration 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''.
    In response to these mandates, recommendations, lessons learned, 
and public input, PHMSA is proposing to make certain changes to the 
Hazardous Liquid Pipeline Safety Regulations. The first and second 
proposals are to extend reporting requirements to all hazardous liquid 
gravity and gathering lines. The collection of information about these 
lines 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 are adequate.
    The third proposal is to require inspections of pipelines in areas 
affected by extreme weather, natural disasters, and other similar 
events. Such inspections will ensure that pipelines

[[Page 61611]]

are still capable of being safely operated after these events. The 
fourth proposal is to require periodic inline integrity assessments of 
hazardous liquid pipelines that are located outside of HCAs. HCA's are 
already covered under the IM program requirements. These assessments 
will provide critical information about the condition of these 
pipelines, including the existence of internal and external corrosion 
and deformation anomalies.
    The fifth proposal is to require the use of leak detection systems 
on hazardous liquid pipelines in all locations. The use of such systems 
will help to mitigate the effects of hazardous liquid pipeline failures 
that occur outside of HCAs. The sixth proposal is to modify the 
provisions for making pipeline repairs. Additional conservatism will be 
incorporated into the existing repair criteria and an adjusted schedule 
will be established to provide greater uniformity. These criteria will 
also be made applicable to all hazardous liquid pipelines, with an 
extended timeframe for making repairs outside of HCAs.
    The seventh proposal is to require that all pipelines subject to 
the IM requirements be capable of accommodating inline inspection tools 
within 20 years, unless the basic construction of a pipeline cannot be 
modified to permit that accommodation. Inline 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, other 
regulations will be clarified to improve certainty and compliance. 
PHMSA estimates that 421 hazardous liquid operators may incur costs to 
comply with the proposed rule. The estimated annual costs for the 
different requirements range from approximately $1,000 to $16.7 
million, with aggregate costs of approximately $22.4 million. These 
wide ranges exist because the requirements vary widely. For example, 
some requirements apply only to pipelines within HCAs, some only to 
those outside HCAs, and some to both; other requirements apply only to 
onshore pipelines, and others to both on- and offshore; the length of 
pipeline, and the number of operators affected both vary for the 
different requirements. These proposals are designed to mitigate or 
prevent some number of hazardous liquid pipeline incidents resulting in 
annualized benefits estimated between approximately $3.5 and $17.7 
million, depending on the requirement. 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 considered in this analysis. The dollar value of 
fatalities, injuries, and property damages due to pipeline incidents 
are societal costs and their prevention represents potential benefits. 
The changes proposed in this Notice of Proposed Rulemaking (NPRM) are 
expected to enhance overall pipeline safety and protection of the 
environment.

II. Background and NPRM Proposals

    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). Like its predecessor, the 
Natural Gas Pipeline Safety Act (NGPSA) of 1968 (Pub. L. 90-481), the 
HLPSA provides the Secretary of Transportation (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. 
Performance-based safety standards are generally favored (i.e., a 
particular objective is specified, but the method of achieving that 
objective is not). Risk management principles play a critical role in 
the IM requirements for HCA's.
    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. The states 
may submit a certification to regulate the safety standards and 
practices for intrastate pipelines. States certified to regulate their 
intrastate lines can also enter into agreements with PHMSA to serve as 
an agent for inspecting interstate facilities.
    Most state pipeline safety programs are administered by public 
utility commissions. These state authorities must adopt the Pipeline 
Safety Regulations as part of a certification or agreement, but can 
establish more stringent safety standards for those intrastate pipeline 
facilities that they have responsibility to regulate. PHMSA cannot 
regulate the safety standards or practices for an intrastate pipeline 
facility if a state has a current certification to regulate such 
facilities.
    Congress recently enacted the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (The Act). 
That legislation included several provisions that are relevant to the 
regulation of hazardous liquid pipelines. As part of the rulemaking 
process, PHMSA presented proposed changes in response to this Act in an 
ANPRM published in the Federal Register on October 18, 2010, (75 FR 
63774). This NPRM will, in the paragraphs that follow, describe each of 
the proposals PHMSA will make along with a statement of need for each 
and an explanation of how each of these proposals improve the pipeline 
safety regulations.

 Extend Certain Reporting Requirements to All Gravity and Rural 
Hazardous Liquid Gathering Lines

    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 are capable of building up large amounts 
of pressure. 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.
    In order for PHMSA to effectively analyze safety performance and 
pipeline 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)), and that authority was not 
affected by any of the provisions in the Pipeline Safety Act of 2011. 
Accordingly, PHMSA is proposing to add 49 CFR 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. 
PHMSA estimates that, at most, five hazardous liquid pipeline operators 
will be affected. Based on comments from API-AOPL to the ANPRM, 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 proposing to extend the reporting requirements of 
part 195 to all hazardous liquid gathering lines. According to the 
legislative history, Congress originally opposed any

[[Page 61612]]

regulation of rural gathering lines in the Hazardous Liquid Pipeline 
Safety Act of 1979 (Pub. L. 96-129) for policy reasons (i.e., those 
lines did not present a significant risk to public safety to justify 
federal regulation based on the data available at that time). See S. 
REP. NO. 96-182 (May 15, 1979), reprinted in 1979 U.S.C.C.A.N. 1971, 
1972. However, Congress eventually relaxed that prohibition in the 
Pipeline Safety Act of 1992 (Pub. L. 102-508) and 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 certain policy judgments in 
implementing those statutory provisions based on the information 
available at that time.
    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. 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. The 
NTSB has also raised concerns about the safety of hazardous liquid 
gathering lines in the Gulf of Mexico and its inlets, which are only 
subject to certain inspection and reburial requirements.\1\
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    \1\ https://app.ntsb.gov/news/2010/100624b.html.
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    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,'' \2\ that was performed 
by the Oak Ridge National Laboratory and published on May 8, 2015, 
PHMSA is proposing additional regulations to ensure the safety of 
hazardous liquid gathering lines.
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    \2\ https://www.phmsa.dot.gov/pv_obj_cache/pv_obj_id_7B2B80704EBC3EBABDB5B9F701F184E0854F3600/filename/report_to_congress_on_gathering_lines.pdf.
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    In order for PHMSA to effectively analyze safety performance and 
pipeline 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)), and that authority was not 
affected by any of the provisions in the Pipeline Safety Act of 2011. 
Accordingly, PHMSA is proposing 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.
    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 adopted a 
regulation in a June 2008 final rule (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 maximum operating pressure according to 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 located in a 
rural area that is not unusually sensitive to environmental damage.'') 
and Congress did not remove this exemption in the 2011 Act. However, 
the 2011 Act did require that PHMSA review whether currently 
unregulated gathering lines should be made subject to the same 
regulations as other pipelines.

Require Inspections of Pipelines in Areas Affected by Extreme Weather, 
Natural Disasters, and Other Similar Events

    In July 2011 a pipeline failure occurred near Laurel, Montana, 
causing the release of an estimated 1,000 barrels of crude oil into the 
Yellowstone River. That area had experienced extensive flooding in the 
weeks leading up to the failure, and the operator has estimated the 
cleanup costs at approximately $135 million. An instance of flooding 
also occurred in 1994 in the State of Texas, leading to 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. As the agency has noted in a series 
of advisory bulletins, hurricanes are 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, 2004 
(70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)).
    These 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 is proposing 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, under this proposal an operator must inspect all 
potentially affected pipeline facilities post extreme weather event to 
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 inspection must occur within 72 hours after the cessation 
of the event, or as soon as the affected area can be safely accessed by 
the personnel and equipment required to perform the inspection. PHMSA 
has found that 72 hours is reasonable and achievable in most cases. If 
an adverse condition is found, the operator must take appropriate 
remedial action to ensure the safe operation of a pipeline based on the 
information obtained as a result of performing the inspection. Such 
actions might include, but are not limited to:
     Reducing the operating pressure or shutting down the 
pipeline;
     Modifying, repairing, or replacing any damaged pipeline 
facilities;
     Preventing, mitigating, or eliminating any unsafe 
conditions in the pipeline right-of-ways (ROWS);
     Performing additional patrols, surveys, tests, or 
inspections;
     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 proposal is based on the experience of PHMSA and is expected 
to increase the likelihood that safety

[[Page 61613]]

conditions will be found earlier and responded to more quickly. PHMSA 
invites comment on this and other proposals in this NPRM. In regard to 
this proposal, PHMSA has particular interest in additional comments 
concerning how operators currently respond to these events, what type 
of events are encountered and if a 72 hour response time is reasonable.

Require Periodic Assessments of Pipelines That Are Not Already Covered 
Under the IM Program Requirements

    PHMSA is proposing to require 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 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 inline inspection 
(ILI) tool at least once every 10 years. PHMSA needs operators to 
complete assessments in HCAs followed by assessments in non-HCAs. Other 
assessment methods could be used if an operator provides the Office of 
Pipeline Safety (OPS) with prior written notice that a pipeline is not 
capable of accommodating an ILI tool. The written notice provided to 
PHMSA must include a technical demonstration of why the pipeline is not 
capable of accommodating an ILI tool and what alternative technology 
the operator proposes to use. The operator must also detail how the 
alternative technology would provide a substantially equivalent 
understanding of the pipeline's condition in light of the threats that 
could affect its safe operation. Such alternative technologies would 
include hydrostatic pressure testing or appropriate forms of direct 
assessment.
    The individuals who review the results of these periodic 
assessments would need to be qualified by knowledge, training, and 
experience and would 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 would 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 would be 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, test, and repairs (see Sec.  195.404), and taking 
appropriate remedial action under Sec.  195.422, as discussed below. 
Section 195.11 would also be amended to subject regulated onshore 
gathering lines to the periodic assessment requirement.
    PHMSA believes by proposing the above amendment to the existing 
pipeline safety regulations, safety will be increased for all pipelines 
both in and out of HCAs. Such a requirement would ensure operators 
obtain information necessary for prompt detection and remediation of 
corrosion and other deformation anomalies in all locations, not just 
HCAs. Currently, operators have indicated that they are performing ILI 
assessments on a large majority of their pipelines even though no 
regulation requires them to do so outside of HCAs. PHMSA wants to 
ensure that current assessment rates continue and expand to those areas 
not voluntarily assessed. Of the many methods to assess, PHMSA has 
found that ILI in many cases is the most efficient and effective. PHMSA 
considered alternatives to its proposal that would likely have lower 
overall costs and benefits, but potentially higher net benefits. For 
instance, PHMSA considered limiting the proposed expansion of certain 
IM requirements to those pipelines where a spill could affect a 
building or occupied site such as a playground, or highway. Under this 
alternative, pipelines in a location where a spill could not affect a 
building, occupied site, or highway would not be subject to these new 
requirements. However, this alternative would offer less protection to 
the natural environment, including sensitive and protected habitats and 
species. PHMSA also considered alternative assessment intervals to the 
proposed 10 year interval, such as a 15- or 20-year interval. However, 
substantial changes to pipeline integrity can occur in a short 
timeframe. PHMSA declined to propose these alternatives because they 
would provide fewer benefits than the proposed approach. More 
specifically, liquid spills, even in remote areas, can result in 
environmental damage necessitating clean up and incurring restoration 
costs and lost use and nonuse values. If pipe is not assessed and 
repaired in accordance with this proposal, liquid spills are likely to 
occur.
    Also, a longer interval between assessments would increase risks of 
integrity-related failure compared to PHMSA's proposal. PHMSA was 
unable to quantify the benefits and costs of these alternatives due to 
limitations in available information, such as the amount of unassessed 
pipe where a spill could not affect a building, occupied site, or 
highway; the environmental impact of spills from such pipe; and the 
incremental reduction in benefit between 10-year and alternative 
interval periods. PHMSA seeks public comments on these alternatives, 
and the regulatory impact analysis contains specific questions for 
public comment on quantifying these alternatives.

 Modify the IM Repair Criteria and Apply Those Same Criteria to Any 
Pipeline Where the Operator Has Identified Repair Conditions

    Inspection experience indicates a weakness in current repair 
criteria. Specifically, the current repair criteria in non-HCAs 
(immediate and reasonable time) does not specify anomaly or repair time 
frames. It is left entirely at the operator's discretion. Therefore, 
PHMSA is proposing to modify the IM pipeline repair criteria and to 
apply the criteria to non-IM pipeline repairs. Specifically, the 
criteria in Sec.  195.452(h) for IM repairs would be modified to:
     Categorize bottom-side dents with stress risers as 
immediate repair conditions;
     Require immediate repairs whenever the calculated burst 
pressure is less than 1.1 times maximum operating pressure;
     Eliminate the 60-day and 180-day repair categories; and
     Establish a new, consolidated 270-day repair category.
    PHMSA is also proposing 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.
    PHMSA believes that these changes will ensure that immediate action 
is taken to remediate anomalies that present an imminent threat to the 
integrity of hazardous liquid pipelines in all locations. Moreover, 
many anomalies that would not qualify as immediate repairs under the 
current criteria will meet that requirement as a result of the 
additional conservatism

[[Page 61614]]

that will be incorporated into the burst pressure calculations. The new 
time frames for performing non-immediate repairs will also allow 
operators to remediate those conditions in a timely manner while 
allocating resources to those areas that present a higher risk of harm 
to the public, property, and the environment. The existing requirements 
in Sec.  195.422 would also be modified to include a general 
requirement for performing all other repairs within a reasonable time. 
A proposed amendment to Sec.  195.11 would extend these new pipeline 
remediation requirements to regulated onshore gathering lines.
    As a result of these changes, PHMSA would modify the existing 
general requirements for pipeline repairs in Sec.  195.401(b). 
Paragraph (b)(1) would be modified to reference the new timeframes in 
Sec.  195.422(d) and (e) for remediating conditions that could 
adversely affect the safe operation of a pipeline segment not subject 
to the IM requirements in Sec.  195.452. The requirements in paragraph 
(b)(2) for IM repairs under Sec.  195.452(h) will be retained without 
change. A new paragraph (b)(3) will be added, however, to 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, including those covered 
by the timeframes specified in Sec. Sec.  195.422(d) and (e) and 
195.452(h).

Expand the Use of Leak Detection Systems for All Hazardous Liquid 
Pipelines

    PHMSA is proposing to amend Sec.  195.134 to require that all new 
hazardous liquid pipelines be designed to include leak detection 
systems. Recent pipeline accidents, including a pair of related 
failures that occurred in 2010 on a crude oil pipeline in Salt Lake 
City, Utah, corroborate the significance of having an adequate means 
for identifying leaks in all locations. PHMSA, aware of the 
significance of leak detection, held two recent workshops in Rockville, 
Maryland on March 27-28 of 2012. 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.
    Currently, part 195 contains mandatory leak detection requirements 
for hazardous liquid pipelines that could affect an HCA.
    Congress included additional requirements for leak detection 
systems in section 8 of the Pipeline Safety Act of 2011. 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 consequence of 
establishing additional standards for the use of those systems. To 
provide Congress with an opportunity to review that report, the 
Secretary is prohibited from issuing any final leak detection 
regulations for a specified time period (i.e., 2 years from the date of 
the enactment of the Pipeline Safety Act of 2011, or 1-year after the 
submission of the leak detection report to Congress, whichever is 
earlier), unless a condition exists that poses a risk to public safety, 
property, or the environment, or is an imminent hazard, and the 
issuance of such regulations would address that risk or hazard. Other 
provisions in part 195 help to detect and mitigate the effects of 
pipeline leaks, including the Right of Way (ROW).
    In addition to modifying Sec.  195.444 to require a means for 
detecting leaks on all portions of a hazardous liquid pipeline system, 
PHMSA is proposing that operators be required to have an evaluation 
performed to determine what kinds of systems must be installed to 
adequately protect the public, property, and the environment. The 
factors that must be considered in performing that evaluation would 
include the characteristics and history of the affected pipeline, the 
capabilities of the available leak detection systems, and the location 
of emergency response personnel. A proposed amendment to Sec.  195.11 
would extend these new leak detection requirements to regulated onshore 
gathering lines. PHMSA is retaining and is not proposing any 
modification to the requirement in Sec. Sec.  195.134 and 195.444 that 
each new computational leak detection system comply with the applicable 
requirements in the API RP 1130 standard.
    PHMSA does not propose to make any additional changes to the 
regulations concerning specific leak detection requirements at this 
time. PHMSA will be studying this issue further and may make proposals 
concerning this topic in a later rulemaking. PHMSA recently publicly 
provided the results of the 2012 Keifner and Associates study of leak 
detection systems in the pipeline industry, including the current state 
of technology.

Increase the Use of Inline Inspection Tools

    PHMSA is proposing to require that all hazardous liquid pipelines 
in HCA's 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 are designed to accommodate 
inline inspection tools. The basis for these requirements was a 1988 
law that addressed the Secretary's authority with regard to requiring 
the accommodation 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).
    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).
    As the Research and Special Programs Administration (RSPA), (a 
predecessor agency of PHMSA) explained in the final rule April 12, 1994 
(59 FR 17275) that promulgated Sec.  195.120, ``[t]he 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.'' April 2, 1994, 
(59 FR 17279). 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 April 2, 1994, (59 FR 
17275). RSPA established requirements for the use of ILI tools in 
pipelines that could affect HCAs in the December 2000 IM final rule 
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.

[[Page 61615]]

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.
    PHMSA is proposing to use the authority provided in section 
60102(f)(1)(B) to further facilitate the ``gradual elimination'' of 
pipelines that are not capable of accommodating smart pigs. PHMSA would 
limit 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, and other unforeseen construction problems. PHMSA believes 
that an exception should still be available for emergencies and where 
the basic construction of a pipeline makes that accommodation 
impracticable, but that the other, less urgent circumstances listed in 
the regulation are no longer appropriate. Accordingly, the allowances 
for construction-related time constraints and problems would be 
repealed.
    Modern ILI tools are capable of providing a relatively complete 
examination of the entire length of a pipeline, including information 
about threats that cannot always be identified using other assessment 
methods. 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. Similarly, external corrosion direct assessment (ECDA) can 
identify instances where coating damage may be affecting pipeline 
integrity, but additional activities, including follow-up excavations 
and direct examinations, must be performed to verify the extent of that 
threat. ECDA also provides less information about the internal 
condition of a pipe than ILI tools.
    As with new pipelines, operators will be allowed to petition the 
PHMSA Administrator for a finding that the basic construction, (i.e., 
terrain or location, of a pipeline or an emergency) will not permit the 
accommodation of a smart pig.

Clarify Other Requirements

    PHMSA is also proposing 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 correct an inconsistency in 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 one-year after the 
pipeline begins operation. These provisions are inconsistent as the 
identification could affect segments, and performance of baseline 
assessments are elements of the written IM program. PHMSA would amend 
the table in (b)(1) to resolve this inconsistency by eliminating the 
one-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.
    A decade's worth of IM inspection experience has shown that many 
operators are performing inadequate information analyses (e.g., they 
are collecting information, but not affording it sufficient 
consideration). Integration is one of the most important aspects of the 
IM program because it is used in identifying interactions between 
threats or conditions affecting the pipeline and in setting priorities 
for dealing with identified issues. For example, evidence of potential 
corrosion in an area with foreign line crossings and recent aerial 
patrol indications of excavation activity could indicate a priority 
need for further investigation. Consideration of each of these factors 
individually would not reveal any need for priority attention. PHMSA is 
concerned that a major benefit to pipeline safety intended in the 
initial rule is not being realized because of inadequate information 
analyses.
    For this reason, PHMSA is proposing to add additional specificity 
to paragraph (g) by establishing a number of pipeline attributes that 
must be included in these analyses and to require explicitly that 
operators integrate analyzed information. PHMSA is also proposing that 
operators 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 proposing that operators verify their segment 
identification 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. PHMSA believes that operators should periodically re-visit 
their initial analyses to determine whether they need to be updated. 
New HCAs may be identified. Construction activities or erosion near the 
pipeline could change local topography in a way that could cause 
product released in an accident to travel further 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 larger area being affected by a potential release if the original 
segment identification relied on emergency response to limit the 
transport of released product.
    The change that PHMSA is proposing would not require that operators 
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 identification. If so, the operator would be required to 
perform a new analysis to validate or change the endpoints of the 
segments affected by the change.
    Third, PHMSA is proposing to clarify, through the use of an 
explicit reference that the IM requirements apply to portions of 
``pipelines'' 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. 
Through IM inspections,

[[Page 61616]]

PHMSA has learned 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 Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011 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 is proposing 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.

III. Analysis of Advance Notice of Proposed Rulemaking

    On October 18, 2010, (75 FR 63774), PHMSA published an ANPRM asking 
the public to comment on several proposed changes to part 195. The 
ANPRM sought comments on:
     Scope of part 195 and existing regulatory exceptions;
     Criteria for designation of HCAs;
     Leak detection and emergency flow restricting devices;
     Valve spacing;
     Repair criteria outside of HCAs; and
     Stress corrosion cracking.

The ANPRM may be viewed at https://www.regulations.gov by searching for 
Docket ID PHMSA-2010-0229.
    Twenty-one organizations and individuals submitted comments in 
response to the ANPRM. The individual docket item numbers are listed 
for each comment.

 Associations representing pipeline operators (trade 
associations)
    [cir] American Petroleum Institute--Association of Oil Pipelines 
(API-AOPL) (PHMSA-2010-0229-0030)
    [cir] Independent Petroleum Association of America (IPAA) (PHMSA-
2010- 0229-0024)
    [cir] Canadian Energy Pipeline Association (CEPA) (PHMSA-2010-0229-
0008)
    [cir] Oklahoma Independent Petroleum Association (OIPA) (PHMSA-
2010- 0229-0018)
    [cir] Texas Pipeline Association (TPA) (PHMSA-2010-0229-0011)
    [cir] Louisiana Midcontinent Oil & Gas Association (LMOGA) (PHMSA-
2010-0229-0018)
    [cir] Texas Oil & Gas Association (TxOGA) (PHMSA-2010-0229-0022)
 Transmission and Distribution Pipeline Companies
    [cir] TransCanada Keystone (PHMSA-2010-0229-0027)
 Government/Municipalities
    [cir] Defense Logistics Agency (DLA) (PHMSA-2010-0229-0016)
    [cir] Metro Area Water Utility Commission (MAWUC) (PHMSA-2010-0229-
0031)
    [cir] North Slope Borough (NSB) (PHMSA-2010-0229-0012)
 Pipeline Safety Regulators
    [cir] National Association of Pipeline Safety Representatives 
(NAPSR) (PHMSA-2010-0229-0032)
 Citizens' Groups
    [cir] Pipeline Safety Trust (PST) (PHMSA-2010-0229-0014)
    [cir] Cook Inlet Regional Citizens Advisory Council (CRAC)) (PHMSA-
2010-0229-0019)
    [cir] The Wilderness Society (TWS) (PHMSA-2010-0229-0025)
    [cir] National Resources Defense Council et al. (NRDC) (PHMSA-2010-
0229-0021)
    [cir] Alaska Wilderness League et al. (AKW) (PHMSA-2010-0229-0026)
 Citizens
    [cir] Patrick Coyle (PHMSA-2010-0229-0002)
    [cir] Marian J. Stec (PHMSA-2010-0229-0007)
    [cir] Pamela A. Miller (PHMSA-2010-0229-0013)
    [cir] Anonymous (PHMSA-2010-0229-0005) (The anonymous comment dealt 
with quality of drinking water and release permits under the Clean 
Water Act.

These topics are beyond the scope of PHMSA's jurisdiction and are not 
discussed further).
    Comments are reviewed in the order the ANPRM presented questions 
for comment. PHMSA responses to the comments follow.

A. Scope of Part 195 and Existing Regulatory Exceptions

Comments
    API-AOPL, LMOGA, TxOGA, and TransCanada Keystone expressed support 
for the gravity line exception. These commenters stated that gravity 
lines are short, pose little risk, and are usually located within other 
regulated facilities, such as tank farms. NAPSR did not support a 
complete repeal of this exception, suggesting there was no data to 
support such an action. NAPSR did suggest that the exception should not 
apply to ethanol pipelines, which are very susceptible to internal 
corrosion.
    MAWUC indicated that gravity lines in HCAs should be regulated 
because of the sensitivity of these areas. MAWUC further stated that 
these lines (and other rural onshore gathering lines) contain 
contaminants that are not present in products carried by other 
pipelines, that these contaminants are dangerous to pipeline workers, 
and that the impact of releases from these pipelines on the environment 
is the same as releases from regulated pipelines.
Response
    PHMSA does not, at this time, intend to repeal the exemption for 
gravity lines, but does propose to extend reporting requirements to all 
hazardous liquid gravity lines. The collection of information about 
these lines 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 are adequate.
Rural Gathering Lines
Comments
    PHMSA received a number of comments on whether to modify or repeal 
the requirements in Sec.  195.1(a)(4). API-AOPL, LMOG, IPAA, OIPA, and 
TxOGA stated that the regulatory exception for rural gathering lines is 
appropriate and should not be repealed or modified. They indicated that 
these lines are the source of a small percentage of spills, and that 
gathering lines in populated areas and near navigable waterways are 
already subject to PHMSA regulation.
    Among citizens' groups, TWS suggested that PHMSA should examine 
federal and state release data from all excepted pipelines and regulate 
those with release rates similar to currently regulated pipelines. PST 
supported expansion of the definition of gathering line to the extent 
statutorily possible to capture all lines. Similarly, CRAC, TWS, and 
AKW indicated the exception should be removed and regulation expanded 
to include produced water lines and production lines. TWS and AKW also 
stated that flow lines, which are currently defined by regulation as 
production facilities, should be reclassified and regulated as 
gathering lines.
    The government/municipalities NSB and MAWUC also commented 
concerning the rural gathering line exception. NSB requested PHMSA 
place a high priority on removing the

[[Page 61617]]

exception for gathering lines. MAWUC supported no gathering line 
exceptions in HCAs.
    Citizen Miller commented that PHMSA should regulate production and 
produced water lines on Alaska's North Slope, because this area is very 
sensitive and includes pristine wetlands and fish and wildlife habitats 
of national and international importance. She further commented that 
river and coastline pipeline routes and crossings in the Arctic and 
subarctic Alaska are particularly of concern due to the rapid change in 
permafrost, as well as high rates of coastal erosion which greatly 
increases the environmental and human impacts of spills.
Response
    PHMSA believes that the requirements of the Pipeline Safety Act of 
2011 and concerns for adequate regulatory oversight can only be 
addressed if PHMSA obtains additional information about gathering 
lines. PHMSA has the statutory authority to gather data for all 
gathering lines (49 U.S.C. 60117(b)), and that authority was not 
affected by any of the provisions in the Pipeline Safety Act of 2011. 
Accordingly, PHMSA is proposing to amend 49 CFR 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.
Carbon Dioxide Lines
    In the ANPRM, PHMSA asked whether the agency should repeal or 
modify the regulatory exception for carbon dioxide pipelines used in 
the well injection and recovery production process. Section 
195.1(b)(10) states that part 195 does not apply to the transportation 
of carbon dioxide downstream from the applicable following point:
    (i) The inlet of a compressor used in the injection of carbon 
dioxide for oil recovery operations, or the point where recycled carbon 
dioxide enters the injection system, whichever is farther upstream; or
    (ii) The connection of the first branch pipeline in the production 
field where the pipeline transports carbon dioxide to an injection well 
or to a header or manifold from which a pipeline branches to an 
injection well.
Comments
    The trade associations, LMOGA, API-AOPL, OIPA, TxOGA, and IPAA, 
commented that PHMSA should not repeal the exception for carbon dioxide 
lines used in the well injection and recovery production process. They 
indicated the potential risk from a production facility carbon dioxide 
pipeline failure is low due to factors of low potential release 
volumes, rapid dispersion, and low potential for human exposure. NAPSR 
suggested the current exception is appropriate and noted that there is 
no data indicating the need for a repeal.
Response
    The regulatory history shows that the exception in Sec.  
195.1(b)(10) is limited in scope and only applies to carbon dioxide 
pipelines that are directly used in the production of hazardous 
liquids. See June 12, 1994, (56 FR 26923) (stating in preamble to 1991 
final rule that ``the exception is limited to lines downstream of where 
carbon dioxide is delivered to a production facility in the vicinity of 
a well site, rather than excepting all the CO2 lines in the broad 
expanses of a production field.''); January 21, 1994, (59 FR 3390) 
(stating in preamble to June 1994 that agency adopted amendment ``to 
clarify that the exception covers pipelines used in the injection of 
carbon dioxide for oil recovery operations.''). Congress has indicated 
that such facilities should not be subject to federal regulation, and 
none of the commenters supported a repeal or modification of this 
exception. Accordingly, PHMSA is not proposing to repeal or modify 
Sec.  195.1(b)(10).
Offshore Lines in State Waters
    In the ANPRM, PHMSA asked whether the agency should repeal or 
modify any of the exceptions for offshore pipelines in state waters.
Comments
    TransCanada Keystone, an industry commenter, and the trade 
associations, API-AOPL, LMOGA and TxOGA, stated the current exception 
should not be changed. API-AOPL pointed out that PHMSA's jurisdiction 
lies only with the transportation of hazardous liquids, not hydrocarbon 
production areas of offshore operations. API-AOPL further stated that 
changing the state waters exception would unnecessarily add a 
duplicative layer of federal regulation.
    The citizens' groups, TWS and AKW, supported removal of this 
exemption and increased enforcement in state waters. Likewise, among 
the government/municipality comments, NSB indicated that the 
regulations need to be expanded to include lines in offshore state 
waters. NSB expressed concerns with lack of state enforcement, high 
corrosion potential, and the sensitivity of the location of the 
offshore lines, such as those in the Beaufort and Chukchi Seas.
    The prohibitions of the Pipeline Safety Act of 2011 do not affect 
PHMSA's authority to ensure the safety of offshore gathering lines 
under other statutory provisions, including if such a line is hazardous 
to life, property, or the environment (49 U.S.C. 60112)). PHMSA also 
notes that the generally-applicable limitation in section 60101(a)(22) 
of the Pipeline Safety Laws only applies to ``onshore production . . . 
facilities,'' and that the states may regulate such intrastate 
facilities (see e.g., Tex. Admin. Code Title. 16, sec. 8.1(a)(1)(D)).
Response
    Congress has indicated that additional federal safety standards may 
be warranted for offshore gathering lines. First, we would note that 
this does not include offshore production pipelines. Section 
195.1(b)(5) states that part 195 does not apply to the: Transportation 
of hazardous liquid or carbon dioxide in an offshore pipeline in state 
waters where the pipeline is located upstream from the outlet flange of 
the following farthest downstream facility; the facility where 
hydrocarbons or carbon dioxide are produced; or the facility where 
produced hydrocarbons or carbon dioxide are first separated, 
dehydrated, or otherwise processed.
    RSPA, a predecessor agency of PHMSA, adopted Sec.  195.1(b)(5) in a 
June 1994 final rule June 28, 1994, (59 FR 33388). Before that time, 
part 195 only included an explicit exception for offshore production 
pipelines located on the Outer Continental Shelf. However, as explained 
in the preamble to the June 1994 final rule, RSPA believed that the 
same exception should be applied to all offshore production pipelines, 
including those located in state waters. Under the federal pipeline 
safety laws, the agency does not regulate production facilities at all. 
Section 21 of the Pipeline Safety Act of 2011 requires the Secretary to 
review the existing federal and state regulations for gathering lines 
and to submit a report to Congress with the results of that review. A 
study on these regulations, titled ``Review of Existing Federal and 
State Regulations for Gas and Hazardous Liquid Lines,'' was performed 
by the Oak Ridge National Laboratory and was published on May 8, 2015. 
The Secretary is also required, if appropriate, to issue regulations 
subjecting hazardous liquid gathering lines located offshore and in the 
inlets of the Gulf of Mexico to the same safety standards that apply to 
all other hazardous gathering lines. Section 21

[[Page 61618]]

states that any such regulations cannot be applied to production 
pipelines or flow lines.
    Congress also included a provision authorizing the collection of 
geospatial or technical data on transportation-related flow lines in 
section 12 of the Pipeline Safety Act of 2011. A transportation-related 
flow line is defined for purposes of that provision as ``a pipeline 
transporting oil off of 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.'' Section 12 also states 
that nothing in that provision ``authorizes the Secretary to prescribe 
standards for the movement of oil through production, refining, or 
manufacturing facilities or through oil production flow lines located 
on the grounds of wells.''
Producer-Operated Pipelines on Outer Continental Shelf
    In the ANPRM, PHMSA asked whether the agency should repeal or 
modify any of the exceptions for pipelines on the OCS.
Comments
    TransCanada Keystone, an industry commenter, and the trade 
associations, API-AOPL, LMOGA, and TxOGA, stated that the current 
exceptions for pipelines on the OCS should remain unchanged. API-AOPL 
requested that PHMSA indicate what impact the Bureau of Ocean Energy 
Management, Regulation and Enforcement's (BOEMRE) recent publication 
regarding Safety and Environmental Management Systems (SEMS) has on 
transportation operators. API-AOPL expressed concern that joint 
jurisdiction, if created by the recent BOEMRE publication, would result 
in regulatory uncertainty.
    NAPSR responded that the exceptions for pipelines on the OCS should 
not be changed as these lines are already regulated by the Department 
of Interior.
Response
    Section 195.1(b)(6) states that part 195 does not apply to the 
transportation of hazardous liquid or carbon dioxide in a pipeline on 
the OCS where the pipeline is located upstream of the point at which 
operating responsibility transfers from a producting operator to a 
transporting operator. Section 195.1(b)(7) further provides that part 
195 does not apply to a pipeline segment upstream (generally seaward) 
of the last valve on the last production facility on the OCS where a 
pipeline on the OCS is producer-operated and crosses into state waters 
without first connecting to a transporting operator's facility on the 
OCS. Safety equipment protecting PHMSA-regulated pipeline segments is 
not excluded. A producing operator of a segment falling within this 
exception may petition the Administrator, under Sec.  190.9 of this 
chapter, for approval to operate under PHMSA regulations governing 
pipeline design, construction, operation, and maintenance. These 
exceptions are designed to ensure that a single federal agency is 
responsible for regulating the safety of any given pipeline segment on 
the OCS (i.e., the Department of Interior for producer-operated 
pipelines and PHMSA for transporter-operated pipelines). See final rule 
codifying 1976 Memorandum of Understanding (MOU) between the 
Departments of Transportation and Interior on the regulation of 
offshore pipelines in Sec.  195.1 August 12, 1976 (41 FR 34040); direct 
final rule codifying 1996 MOU between the Departments of Transportation 
and Interior on the regulation of offshore pipelines in Sec.  195.1 
November 19, 1997 (62 FR 61692); and final rule clarifying regulation 
of producer-operated pipelines that cross the federal-state boundary in 
offshore waters without first connecting to a transporting-operator's 
facility on the OCS) August 5, 2003 (68 FR 46109).
    None of the commenters supported the repeal or modification of 
Sec.  195.1(b)(6) or (7). Accordingly, PHMSA is not proposing to take 
any further action with respect to these two provisions. It should also 
be noted that PHMSA is not responsible for administering another 
federal agency's statutes or regulations.
Breakout Tanks Not Used for Reinjection or Continued Transportation
    In the ANPRM, PHMSA asked for comment on whether the agency should 
expand the extent to which part 195 applies to breakout tanks.
Comments
    PHMSA received several comments on whether the agency should expand 
the extent to which part 195 applies to breakout tanks. API-AOPL, 
supported by the industry commenter, TransCanada Keystone, and the 
trade associations, LMOGA and TxOGA, stated that the current definition 
is appropriate, and that PHMSA should review its current MOU with the 
Environmental Protection Agency (EPA) before making any changes to 
avoid duplicative regulation of these facilities. DLA, a governmental/
municipal entity, echoed the comments of API-AOPL.
    Conversely, NAPSR stated that if PHMSA is referring to the large 
number of small tanks that are technically under PHMSA's authority, but 
currently not regulated, then this exception should be removed.
Response
    The Pipeline Safety Laws provide PHMSA with broad authority to 
regulate ``the storage of hazardous liquid incidental to the movement 
of hazardous liquid by pipeline'' (49 U.S.C. 60101(a)(22)(A)). The term 
``breakout tank'' is defined in Sec.  195.2 to designate which 
aboveground tanks are regulated as breakout under part 195. See Exxon 
Corporation v. U.S. Department of Transportation, 978 F.Supp. 946, 949-
54 (E.D. Wash. 1997).
    As some of the commenters noted, PHMSA has an MOU with EPA on the 
treatment of breakout tanks and bulk storage tanks under the 
requirements of the Oil Pollution Act of 1990. Such agreements can 
ensure the effective regulation of facilities that are subject to 
regulation by more than one federal agency. As in the case of offshore 
pipeline facilities, those agreements can also serve as a guideline on 
whether a tank is transportation related or non-transportation related.
    Accordingly, PHMSA will review its agreements with EPA to determine 
whether any modifications are necessary, but is not proposing to change 
the definition of a ``breakout tank'' in part 195 at this time.
Other Exceptions or Limitations in Part 195
    In the ANPRM, PHMSA asked for comment on whether the agency should 
repeal or modify any of the other exceptions in part 195. API-AOPL, 
supported by several other trade associations, including LMOGA, TxOGA, 
OIPA, and IPAA, commented that the exception in Sec.  195.1(b)(8) for 
transportation of hazardous liquid or carbon dioxide through onshore 
production (including flow lines), refining, or manufacturing 
facilities or storage or in-plant pipeline systems associated with such 
facilities should not be changed. API-AOPL commented that these 
facilities are not within the scope of the Pipeline Safety Laws, 
because they are not typically operated by midstream oil and gas 
pipeline companies operating in the pipeline transportation system. 
These facilities are already covered under a 1972 MOU with EPA and do 
not require further duplicative regulation.
Comments
    API-AOPL commented that the exception in Sec.  195.1(b)(9) for 
piping located on the grounds of a materials

[[Page 61619]]

transportation terminal used exclusively to transfer products between 
non-pipeline modes of transportation should not be changed. This piping 
is typically isolated from pipeline pressure by devices that control 
pressure in the pipeline under Sec.  195.406(b). TransCanada Keystone, 
an industry commenter, supported API-AOPL's comments.
    The citizens' groups NRDC and PST indicated that PHMSA should 
establish additional standards for diluted bitumen. Both groups 
suggested PHMSA establish additional regulations for that commodity due 
to the high temperatures and pressures at which the lines that carry it 
operate.
    Both regulatory associations, NAPSR and MAWUC, commented on other 
exemptions or limitations of the pipeline safety regulations. NAPSR 
indicated that the exemptions for pipelines under 1-mile long that 
serve refining, manufacturing, or terminal facilities should be 
eliminated for ethanol pipelines. NAPSR also requested that PHMSA 
verify that intrastate lines carrying other hazardous liquids, such as 
sulfuric acid, are regulated by the states. MAWUC indicated that there 
should be no regulatory exceptions in HCA segments, because these areas 
must be treated with the highest degree of both prevention and 
emergency remediation measures.
    Among government and municipality commenters, NSB stated that Sec.  
195.1 should be amended to include regulation of all onshore pipelines 
and offshore pipelines in areas of the North Slope. NSB suggests 
regulation should occur where the consequences of a hazardous liquid 
pipeline failure could adversely impact: (1) An endangered, threatened 
or depleted species; (2) subsistence resources and subsistence use 
areas; (3) a drinking water supply; (4) cultural, archeological, and 
historical resources; (5) navigable waterways (including waterways 
navigated by rural residents for the purposes of recreation, commerce, 
and subsistence use); (6) recreational use areas; or (7) the 
functioning of other regulated facilities. Regulation of all high 
pressure, large diameter (6-inch and greater) onshore pipelines and all 
offshore pipelines should start at the wellhead.
    One citizen commented that the river and coastline routes in the 
Arctic and sub-Arctic are particularly of concern because of the rapid 
change in permafrost, as well as high rate of coastal erosion, which 
greatly increase the environmental and human impacts of hazardous 
liquid spills.
Response
    Section 195.1(b)(8) states that part 195 does not apply to the 
transportation of hazardous liquid or carbon dioxide through onshore 
production (including flow lines), refining, or manufacturing 
facilities or storage or in-plant piping systems associated with such 
facilities. That exception is based on section 60101(a)(22) of the 
Pipeline Safety Laws, which exempts the movement of hazardous liquid 
through onshore production, refining, or manufacturing facilities; or 
storage or in-plant piping systems associated with onshore production, 
refining, or manufacturing facilities. Accordingly, PHMSA agrees with 
the commenters that the exception in Sec.  195.1(b)(8) should not be 
changed.
    With respect to the terminal exemption in Sec.  195.1(b)(9)(ii), it 
should first be noted that the term ``Pipeline or pipeline system'' is 
defined in Sec.  195.2 as ``all parts of a pipeline facility through 
which a hazardous liquid or carbon dioxide moves in transportation, 
including, but not limited to, line pipe, valves, and other 
appurtenances connected to line pipe, pumping units, fabricated 
assemblies associated with pumping units, metering and delivery 
stations and fabricated assemblies therein, and breakout tanks.'' The 
term ``Pipeline facility'' is defined in Sec.  195.2 as ``new and 
existing pipe, rights-of-way and any equipment, facility, or building 
used in the transportation of hazardous liquids or carbon dioxide.'' 
Under 49 U.S.C. 60101(a)(22), ``transporting hazardous liquid'' 
includes ``the storage of hazardous liquid incidental to the movement 
of hazardous liquid by pipeline.''
    Section 195.1(b)(9) states that part 195 does not apply to the 
transportation of hazardous liquid or carbon dioxide by vessel, 
aircraft, tank truck, tank car, or other non-pipeline mode of 
transportation or through facilities located on the grounds of a 
materials transportation terminal if the facilities are used 
exclusively to transfer hazardous liquid or carbon dioxide between non-
pipeline modes of transportation or between a non-pipeline mode and a 
pipeline. These facilities do not include any device and associated 
piping that are necessary to control pressure in the pipeline under 
Sec.  195.406(b).
    One of PHMSA's predecessors, the Materials Transportation Bureau 
(MTB), adopted the original version of that exception in a July 1981 
final rule July 27, 1981, (46 FR 38357). In excepting the 
``[t]ransportation of a hazardous liquid by vessel, aircraft, tank 
truck, tank car, or other vehicle or terminal facilities used 
exclusively to transfer hazardous liquids between such modes of 
transportation,'' MTB stated that: [Its] authority to establish minimum 
Federal hazardous liquid pipeline safety standards under the [Hazardous 
Liquid Pipeline Safety Act (HLPSA) of 1979] extends to ``the movement 
of hazardous liquids by pipeline, or their storage incidental to such 
movement.'' The Senate report that accompanied the HLPSA states that, 
``It is not intended that authority over storage facilities extend to 
storage in marine vessels or storage other than those which are 
incidental to pipeline transportation.'' (Sen. Rpt. 96-182, 1st Sess., 
96th Cong. (1979), p. 18.) Earlier laws had vested DOT with extensive 
authority to prescribe safety standards governing the movement of 
hazardous liquids in seagoing vessels, barges, rail cars, trucks or 
aircraft and storage incidental to those forms of transportation. From 
the words of the new HLPSA and the related Senate report language, it 
is clear that Congress did not want to duplicate or overlap any of 
those earlier laws. Thus, HLPSA regulatory authority over storage does 
not extend to any form of transportation other than pipeline or to any 
storage or terminal facilities that are used exclusively for transfer 
of hazardous liquids in or between any of the other forms of 
transportation unless that storage or terminal facility is also 
``incidental'' to a pipeline which is subject to the HLPSA. These 
storage and terminal facilities are expressly excluded from the 
coverage of part 195 July 27, 1981, (46 FR 38358). RSPA modified that 
exception in the final rule June 28, 1994, (59 FR 33388).
    RSPA, however, continued to maintain the exclusion for the 
transportation of hazardous liquids or carbon dioxide by non-pipeline 
modes, and added a more detailed exclusion for transfer piping located 
on the grounds of a materials transportation terminal.
    The regulatory history demonstrates that the exception in Sec.  
195.1(b)(9) is designed to exclude piping used in transfers to non-
pipeline modes of transportation and the facilities and piping at 
terminals that are used exclusively for such transfers. The provision 
is drafted to ensure that any piping that is not used exclusively to 
transfer product between non-pipeline modes or transportation between a 
non-pipeline mode and a pipeline and facilities are subject to 
regulation by PHMSA. None of the commenters argued in favor of changing 
the exception, and there is no information to suggest that such action 
is necessary at this time. Accordingly, PHMSA is not

[[Page 61620]]

proposing to modify or repeal Sec.  195.1(b)(9).
    With regard to the remaining comments, section 16 of the Pipeline 
Safety Act of 2011 requires the Secretary to perform a comprehensive 
review of whether the requirements in part 195 are sufficient to ensure 
the safety of pipelines that transport diluted bitumen (dilbit) and to 
provide Congress with a report on the results of that review. That 
review, titled ``Effects of Diluted Bitumen on Crude Oil Transmission 
Pipelines,'' was performed by the National Academy of Sciences and was 
published in 2013. The review found there were no causes of pipeline 
failure unique to the transportation of diluted bitumen, or evidence of 
chemical or physical properties of diluted bitumen shipments that are 
outside the range of other crude oil shipments, or any other aspect of 
diluted bitumen's transportation by pipeline that would make it more 
likely than other crude oils to cause releases.\3\ However, the safety 
proposals in this rulemaking address all hazardous liquid pipelines, 
which include pipelines that transport diluted bitumen.
---------------------------------------------------------------------------

    \3\ https://phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Pipeline/Dilbit_1_Transmittal_to_Congress.pdf.
---------------------------------------------------------------------------

    Multiproduct petroleum pipelines transporting ethanol blends of up 
to 95% are currently regulated by PHMSA under part 195 and no major 
ethanol spills have occurred on these pipelines. PHMSA is performing 
additional research into the technical issues associated with the 
transportation of ethanol by pipeline and will use that information to 
determine whether such transportation should be subject to any 
additional safety requirements in the future. This NPRM proposes to 
conform part 195 with 49 U.S.C. 60101(a)(4) making the transportation 
by pipeline of any biofuel that is flammable, toxic, corrosive, or 
would be harmful to the environment if released in significant 
quantities, subject to part 195.
    The requirements for HCA's are addressed in another portion of this 
document. As noted above, PHMSA is proposing to extend the federal 
reporting requirements to all hazardous liquid gathering lines (whether 
onshore, offshore, regulated, or unregulated).
    In conclusion, PHMSA will not be proposing to change or eliminate 
any other regulatory exceptions at this time. The exception for carbon 
dioxide pipelines is limited in scope and only applies to production 
facilities. Although breakout tanks are defined in a way that limits 
the application of part 195, these certain storage tanks may also be 
subject to regulation by EPA. PHMSA continues to study the scope of the 
gathering line exemptions, but is not proposing to modify these or any 
other exemption. At present, nothing indicates that any of the other 
exceptions should be modified as part of this rulemaking proceeding, or 
that the issuance of regulations for underground storage facilities is 
necessary.
Additional Safety Standards for Underground Hazardous Liquid Storage 
Facilities
    The definition of a pipeline facility in part 195 includes ``any 
equipment, facility, or building used in the transportation of 
hazardous liquids . . .'' and, as already noted above, includes storage 
terminals. While surface piping in storage fields located at midstream 
terminal facilities falls within this definition, part 195 does not 
contain comprehensive safety standards for the ``downhole'' underground 
hazardous liquid storage caverns. In addition, surface piping at 
storage fields located either at the production facility where a 
pipeline originates or a destination/consumption facility where a 
pipeline terminates would generally not be considered part of the 
transportation and, therefore, not be regulated by PHMSA in the manner 
that such piping located on the grounds of the midstream terminal 
would. RSPA provided an explanation in a July 1997 advisory bulletin 
June 2, 1997, (62 FR 37118) which the agency issued in response to a 
NTSB recommendation on the regulation of underground storage caverns 
(P-93-9). RSPA noted in that advisory bulletin that a recent report 
indicated that state regulations applied in some form to significant 
percentages of these facilities, and that API had developed a set of 
comprehensive guidelines for the underground storage of liquid 
hydrocarbons. As result of these state regulations, the API guidelines, 
and ``the varying and diverse geology and hydrology of the many sites'' 
RSPA stated that agency had ``decided that generally applicable federal 
standards may not be appropriate for underground storage facilities.'' 
June 2, 1997, (62 FR 37118) RSPA further stated it would be 
``encouraging state action and voluntary industry action as a way to 
assure underground storage safety instead of proposing additional 
federal regulations.'' Id. PHMSA understands that Court decisions 
preempting state from regulating interstate facilities appears to be a 
concern for state regulators.
Comments
    PHMSA requested comment on the promulgation of new or additional 
safety standards for underground hazardous liquid storage. The industry 
commenter, TransCanada Keystone, supported the comments of API-AOPL, as 
did the trade associations LMOGA and TxOGA. API-AOPL stated that the 
current exclusion of the underground cavern is appropriate as they are 
already regulated by the states. API-AOPL indicated that the states are 
better suited to regulate these facilities because of their knowledge 
of these facilities and locations.
    One government/municipality, DLA, commented that there was no need 
for new regulations for underground hazardous liquid storage 
facilities. DLA maintains that these facilities are currently regulated 
for purposes of the Clean Air Act under both 40 CFR parts 112 and 280 
by the EPA.
Response
    None of the commenters supported the issuance of additional 
regulations for underground hazardous liquid storage caverns, and there 
is no information suggesting that such action is necessary at this 
time. Therefore, PHMSA is not proposing to issue any new regulations 
for underground storage of hazardous liquids in this proceeding.
Order in Which Regulatory Changes Should Be Made in to Best Protect the 
Public, Property, or the Environment
Comments
    PHMSA received comments from industry, trade associations, one 
government/municipality, and one regulatory association responding to 
the question on the order of the actions PHMSA should take to best 
protect the public, property, or the environment. API-AOPL, supported 
by TransCanada Keystone and the trade associations, OIPA, TxOGA, and 
LMOGA, indicated that PHMSA's actions should be risk-based. Similarly, 
NAPSR had no recommendation on the order, but suggested that it be 
based on risk.
    The government/municipality NSB requested that PHMSA place a high 
priority on the repeal of regulatory exceptions for gathering of 
hazardous liquids in rural areas, offshore pipelines in state waters, 
and producer-operated lines on the OCS. NSB stated that unregulated 
rural pipelines are located in Unusually Sensitive Areas (USAs) of the 
NSB. These pipelines cross sensitive arctic tundra vegetation and 
impact areas used by endangered species. As North Slope development 
continues to expand to the west, east, and south,

[[Page 61621]]

impacts to NSB communities and USAs will increase.
Response
    PHMSA is proposing to repeal the exception for gravity lines and to 
apply the reporting requirements in part 195 to all gathering lines.

B. Definition of High Consequence Area

    In the ANPRM, PHMSA asked for public comment on whether to modify 
the requirements in part 195 for HCAs. Specifically, PHMSA asked 
whether:
     The criteria for identifying HCAs should be changed to 
incorporate additional pipeline mileage or better reflect risk;
     All navigable waterways should be included within the 
definition of an HCA;
     The process for making HCA determinations on pipeline ROWs 
can be improved;
     The public and state and local governments should be more 
involved in making HCA determinations;
     Additional safety requirements should be developed for 
areas outside of HCAs; and
     Major road and railway crossings should be included within 
the definition of an HCA.
    As discussed in detail later in the Background and NPRM Proposals 
section, PHMSA is proposing to adopt additional safety standards for 
pipelines that are located outside of areas that could affect an HCA. 
These measures will increase the safety of all of the nation's 
pipelines without necessitating any change to the HCA definition; 
therefore, PHMSA is not taking any further action on that proposal at 
this time.
Expanding the Definition of HCA To Include Additional Pipeline Mileage
    In the ANPRM, PHMSA asked whether the current criteria for 
identifying HCAs should be modified to incorporate additional pipeline 
mileage.
Comments
    TransCanada Keystone recommended that PHMSA further define the 
meaning of an HCA, and that the agency provide greater clarity with 
respect to the HCA classification, including the magnitude of impacts 
that differentiate HCAs from other areas.
    API-AOPL, supported by the trade associations, TxOGA and LMOGA, and 
an industry commenter, TransCanada Keystone, stated that the current 
criteria should not be changed. API-AOPL stated that PHMSA should serve 
a clearinghouse function by displaying HCA information on the NPMS, 
with updates every 10 years based on census information. API-AOPL 
further noted that ``other populated areas'' includes Census-delineated 
areas, like Metropolitan Statistical Areas (MSA) and Consolidated 
Metropolitan Statistical Areas, which are not densely populated, and 
that the current HCA criteria are thus conservative. API-AOPL also 
stated that the current ability of operators to demonstrate why 
segments of pipeline could not affect an HCA should be retained.
    The trade associations, OIPA and TPA, suggested that more data is 
needed to make a decision on HCA definition expansion, and that any 
changes would likely impact small operators.
    Among citizens' groups, PST favored expanding the IM requirements 
to all hazardous liquid lines, with initial inspections required within 
5 years of identification. PST stated that using census data to 
designate high population and other population areas is arbitrary and 
not necessarily a predictor of risk. Noting that the public could not 
fully comment because HCA boundaries are not publicly available (for 
security reasons); PST stated that the definition of HCA should be 
expanded to include national parks, monuments, recreation areas, and 
national forests. PST also pointed to the recent trend in extreme 
accidents in HCAs.
    Two other citizens' groups, AKW and NRDC, commented. AKW requested 
that the criteria be changed. NRDC indicated that PHMSA should have a 
broader definition of HCAs, particularly with respect to ecological 
resources and drinking water criterion.
    NAPSR commented that the current criteria are generally adequate, 
but that other threats and risks could be considered, including 
petroleum product supply loss, leaks that could affect private wells, 
and impacts to major infrastructure.
    NSB favored an expansion of HCAs to include pipelines located in 
subsistence areas, cultural resources, archeological, historical, and 
recreational areas of significance and offshore.
Response
    Congress recently directed the Secretary to prepare a report on 
whether the IM requirements should be extended to pipelines outside of 
areas that could affect HCAs. The Secretary is prohibited from issuing 
any final regulations that would expand those requirements during a 
subsequent Congressional review period, unless those regulations are 
necessary to address a condition posing a risk to public safety, 
property, or the environment, or an imminent hazard. PHMSA is preparing 
the Secretary's report to Congress on the need to expand the IM 
requirements and is not proposing to change the definition of an HCA to 
incorporate additional pipeline mileage at this time.
    PHMSA is, however, proposing to adopt additional safety standards 
for pipelines that are not covered under the IM program requirements. 
The proposals are detailed later in this NPRM under the Background and 
NPRM proposals section.
    PHMSA is aware of its obligation to consider other locations near 
pipeline ROWs in defining USAs, including ``critical wetlands, riverine 
or estuarine systems, national parks, wilderness areas, wildlife 
preservation areas or refuges, wild and scenic rivers, or critical 
habitat areas for threatened and endangered species.'' However, PHMSA 
is not proposing to make any of these areas USAs in light of the new 
requirements that are being proposed for non-IM pipelines. PHMSA will 
be considering whether to include these locations in the HCA definition 
in performing the evaluation required under section 5 of the Pipeline 
Safety Act of 2011 and will comply with the applicable provisions of 
that legislation before taking any final regulatory action to adopt the 
proposed requirements for non-IM pipelines.
Modifying the Definition of HCA to Better Reflect Risk
    PHMSA asked whether the criteria for identifying HCAs should be 
changed to better reflect risk.
Comments
    TransCanada Keystone's comment focused specifically on the 
classification of groundwater USAs in Sec.  195.6, stating that 
groundwater HCA buffers should not be expanded, and that the existing 
criteria, which identify community water intakes where contamination 
has the potential to cause greater impacts compared to other areas, are 
sufficient.
    API-AOPL stated that there are various risk factors applicable to 
HCA classifications and that the current definition should not be 
changed. API-AOPL recommended that buffer zones be used as an 
acceptable alternative to the more detailed ``could affect'' analysis 
for new, expanded, or modified HCAs. API-AOPL also suggested that 
operators should retain the ability, with technical justification, to 
determine whether a pipeline can actually impact an HCA. TransCanada 
Keystone, LMOGA, and TxOGA endorsed API-AOPL's comments. TPA, the other 
trade association commenter, mentioned that

[[Page 61622]]

more data was needed to make a final decision on this matter.
    A number of citizens' groups commented on this issue. NRDC, AKW, 
and TWS indicated the HCA definition needs to be broadened to reflect 
risk and to include entire pipelines in some cases. NRDC stated that 
the threshold for a populated area should be lowered, and that the 
definition of populated areas and USA should be improved. NRDC 
commented that the current HCA definition provides limited protection 
to threatened or endangered species. NRDC also recommended 
strengthening the USA definition to protect more migratory bird areas 
and national landmarks, including national parks, wild and scenic 
rivers, estuaries, wilderness areas, wildlife refuges, and drinking 
water sources, including private wells and open source aquifers. TWS 
and AKW proposed to revise the HCA criteria to include all 
transportation infrastructure, public lands, waterways, wetlands, and 
cultural, historic, archeological, and recreation sites, including 
subsistence areas.
    NAPSR stated that the current HCA definition should not be changed, 
but that PHMSA should consider incorporating others threats and risks, 
including supply interruptions and small leaks that could affect 
private wells.
    NSB favored changing the existing HCA definition. NSB stated that 
USAs should include subsistence, cultural, archeological, historical, 
and recreational areas of significance within the NSB and offshore 
waters of the Beaufort and Chukchi Seas. NSB suggested a formal process 
for nominating areas that should be afforded HCA status, and that the 
NPMS data should be updated.
    Both MAWUC and DLA indicated the definition could be modified to 
better reflect risk. MAWUC suggested a tiered, prioritized system with 
enforceable criteria that are appropriate for the risk to water 
supplies. DLA stated that higher risk locations should be protected 
instead of simply creating more HCAs.
Response
    PHMSA is not proposing to make any changes to the criteria for 
identifying HCAs at this time. The existing Census-based approach for 
determining high population and other populated areas ensures 
uniformity and provides an adequate margin of safety by including some 
less densely populated areas. None of the commenters offered a more 
effective alternative.
    PHMSA recognizes that other areas of ecological, cultural, or 
national significance could be designated as USAs. However, PHMSA is 
not proposing to add any of these areas in light of the new safety 
standards that are being proposed for hazardous liquid pipelines that 
are not subject to the IM program requirements.
    PHMSA does not support any of the suggested alternative approaches 
for identifying HCAs. The widespread use of the buffer method is not 
justified based on the available information, and the use of a more 
lenient standard in making HCA determinations would not provide 
adequate protection for these sensitive areas. PHMSA will revisit these 
conclusions in preparing the Secretary's report to Congress on 
expanding the IM program for hazardous liquid pipelines.
Commercial Limitation on Navigable Waterways
    The ANPRM posed the question of expansion of the definition of HCAs 
beyond commercially navigable waterways.
Comments
    Several trade associations, API-AOPL, OIPA, and IPAA, and one 
industry representative, TransCanada Keystone, opposed expanding the 
HCA definition beyond commercially navigable waterways. These 
commenters stated that the vast majority of surface waters are already 
covered under the present criteria. TPA stated that adopting a 
navigable waters standard would make every creek an HCA, resulting in a 
significant increase in the burden associated with implementing IM 
requirements.
    Two citizens' groups commented on the phrase ``commercially 
navigable.'' PST also recommended defining HCA to include all ``waters 
of the United States,'' provided PHMSA did not adopt its suggestion to 
apply IM requirements to all regulated pipelines. NRDC proposed to 
amend the term ``commercially navigable waterways'' to include other 
bodies of water that are not necessarily navigable, such as lakes, 
streams, and wetlands.
    Two government/municipalities commented on the commercial 
limitation on navigable waterways. DLA, a government/municipality, 
echoed the comments of the trade associations and TransCanada Keystone 
previously mentioned. NSB requested PHMSA change commercially navigable 
to ``navigable waters'' or ``waters of the U.S.'' to encompass more 
environmentally-sensitive areas.
Response
    Section 195.450 states that an HCA includes any ``waterway where a 
substantial likelihood of commercial navigation exists.'' RSPA first 
proposed to include commercially navigable waterways as HCAs in the 
April 2000 NPRM that contained the original IM requirements for 
hazardous liquid pipelines April 24, 2000, (65 FR 21695). RSPA stated 
that it ``[wa]s including commercially navigable waterways in the 
proposed [HCA] definition[,] [b]ecause these waterways are critical to 
interstate and foreign commerce and supply vital resources to many 
American communities, are a major means of commercial transportation, 
and are a part of a national defense system, a pipeline release in 
these areas could have significant impacts.'' April 24, 2000, (65 FR 
21700).
    RSPA adopted the HCA definition as proposed in the NPRM in the 
final rule December 1, 2000, (65 FR 75378). In the preamble to that 
final rule, RSPA stated that it had received the following comments on 
its proposal to include commercially navigable waterways in the HCA 
definition:
    API and liquid operators questioned the inclusion of commercially 
navigable waterways into the HCA's definition. API pointed out that 
Congress required OPS to identify hazardous liquid pipelines that cross 
waters where a substantial likelihood of commercial navigation exists 
and once identified, issue standards, if necessary, requiring periodic 
inspection of the pipelines in these areas. API said that OPS had not 
determined the necessity for including these waterways in areas that 
trigger additional integrity protections. BP Amoco said the rule should 
be limited to protection of public safety, rather than commercial 
interests. Enbridge and Lakehead also questioned why waterways that are 
not otherwise environmentally sensitive should be included for 
protection.
    EPA Region III said that we should also consider recreational and 
waterways other than those for commercial use. Environmental Defense, 
Batten, City of Austin and other[s] commented that we should consider 
all navigable waterways as HCA's, because of the environmental 
consequences a hazardous liquid release could have on such waters. 
December 1, 2000, (65 FR 75390).
    RSPA provided the following response to those comments:
    ``Our inclusion of commercially navigable waterways for public 
safety and secondary reasons is not based on the ecological sensitivity 
of these

[[Page 61623]]

waterways. Parts of waterways sensitive for ecological purposes are 
covered in the proposed USA definition, to the extent that they contain 
occurrences of a threatened and endangered species, critically 
imperiled or imperiled species, depleted marine mammal, depleted multi-
species area, Western Hemispheric Shorebird Reserve Network or Ramsar 
site. We are including commercially navigable waterways as HCAs because 
these waterways are a major means of commercial transportation, are 
critical to interstate and foreign commerce, supply vital resources to 
many American communities, and are part of a national defense system. A 
pipeline release could have significant consequences on such vital 
areas by interrupting supply operations due to potentially long 
response and recovery operations that occur with hazardous liquid 
spills. December 1, 2000, (65 FR 75391-2).
    For these reasons, RSPA defined HCAs in Sec.  195.450 to include 
commercially navigable waterways.
    Thus, the Pipeline Safety Laws do not necessarily limit the 
definition of an HCA to commercially navigable waterways. RSPA relied 
on several statutes in promulgating the IM requirements for hazardous 
liquid pipelines, including the mandates that required the Secretary to 
establish criteria for identifying pipelines in high density population 
and environmentally sensitive areas (49 U.S.C. 60109(a)(1)) and to 
promulgate standards for ensuring the periodic inspection of these 
lines (49 U.S.C. 60102(f)(2)). Nothing in these provisions or the 
Pipeline Safety Act of 2011 prohibits PHSMA from using its general 
rulemaking authority to apply the hazardous liquid pipeline IM 
regulations to waterways that are not used for commercial navigation. 
Other kinds of waterways are also referenced in the statutory criteria 
that must be considered in defining USAs.
    PHMSA will be considering the expansion of current HCA or the 
extension of critical IM requirements to non-HCAs-when completing the 
Secretary's report to Congress on the need to expand the IM requirement 
under section 5 of the Pipeline Safety Act of 2011. In the meantime, 
PHMSA is not proposing to include any additional waterways in the HCA 
definition.
    PHMSA is, however, proposing to adopt other regulations that will 
increase the safety of our nation's waterways. One such proposal is to 
require leak detection systems for pipelines in all locations, that 
operators perform periodic assessments of pipelines not already covered 
under the IM program requirements, and that new pipeline repair 
criteria be applied to anomalous conditions discovered in all areas. 
Another proposal is to require operators to inspect their pipelines in 
areas affected by extreme weather, natural disasters, and other similar 
events (e.g., flooding, hurricanes, tornados, earthquakes, landslides, 
etc.). Following a disaster event, operators will be required to 
determine whether any conditions exist that could adversely affect the 
safe operation of a pipeline and to take appropriate remedial actions, 
such as reductions in operating pressures and repairs of any damaged 
facilities or equipment.
    In regard to seismic events and earthquakes, in determining whether 
a pipeline has potentially been affected and needs inspection, 
operators should consider relevant factors such as magnitude of the 
earthquake, distance from the epicenter, and pipeline characteristics 
and history. PHMSA recognizes that after considering these factors, 
operators may determine that smaller seismic events do not have the 
potential to affect their pipelines. Based on available studies, 
however, earthquakes over 6.0 in magnitude can potentially damage 
pipelines and operators would be required to inspect these pipelines.
Operator Process and Public Participation in Making HCA Determinations
    PHMSA requested comment on whether the operator's process for 
making HCA determinations should be modified, including by having 
greater involvement by the public and state and local governments.
Comments
    PHMSA received comments from industry, trade associations, and one 
regulatory association. API-AOPL supported the existing process for 
identifying HCAs and suggested that any input from local communities 
should be through the regulating agency, rather than pipeline 
operators. OPIA and IPAA noted that a consistent and reliable approach 
is needed to prevent variations that would result in unnecessary 
confusion.
    The trade associations, TxOGA, LMOGA, API-AOPL, supported by 
TransCanada Keystone, indicated that operators perform geographic 
overlay of their pipeline systems with PHMSA-determined HCAs. Operators 
also utilize the ``could affect'' analysis, which typically considers 
technical assessments using dispersion models. Through the process of 
HCA evaluation, operators are sometimes able to determine, with 
technical justification, that their assets are not capable of impacting 
an HCA.
    NAPSR indicated that PHMSA could consider adding minimum time 
intervals for operators to review HCA identifications, including a 
shorter time interval if a pipeline is routed through high population 
areas. NAPSR also stated that there are areas where private wells have 
been extremely affected by small leaks that go undetected for years, 
that this is especially true in areas of sandy soil where leaks do not 
necessarily bubble up to the surface, and that there should be some 
consideration to address these ``seepers'' that have very large total 
leak volume over time.
    On the matter of greater public participation, TransCanada Keystone 
suggested that PHMSA collect data from the states and provide updated 
HCA information for operator use. The trade associations, LMOGA, TxOGA 
and API-AOPL, supported by TransCanada Keystone, recommended that 
additional local involvement be routed through the regulating agency, 
such as PHMSA. TPA, in contrast, stated that there should be no 
requirement for public involvement. OIPA and IPAA held that a 
consistent and reliable approach is needed for the issue of public 
involvement.
    Among the citizens' groups, NRDC supported additional public 
involvement. Several commenters, including NRDC, PST, and TWS, 
recommended that the NPMS be revised to display all HCAs so that the 
public can be better informed.
    One regulatory association, NAPSR, suggested that the public be 
allowed to comment. NAPSR recognized that PHMSA has a process in place 
for HCA selection that can be enhanced if the public is allowed to 
provide input. NAPSR stated that the general public and local 
communities often recognize changes in areas near pipelines before 
operators.
    Government and municipal commenters supported local involvement in 
the HCA determination process. MAWUC commented that it is important 
that local communities and water suppliers play a role in preventing 
and minimizing pipeline failures, including HCA identification. DLA 
also supported additional public involvement. NSB recommended that 
state and local governments, as well as local tribes, villages, and the 
Alaskan Eskimo Whaling Commission, have a role in making HCA 
determinations.

[[Page 61624]]

Response
    Congress included new requirements for promoting public education 
and awareness in section 6 of the Pipeline Safety Act of 2011. 
Specifically, that provision requires PHMSA (1) to maintain, and update 
on a biennial basis, a map of designated HCAs in the NPMS; (2) to 
establish a program that promotes greater awareness of the existence of 
the NPMS to state and local emergency responders and other interested 
parties, to include the issuance of guidance on using the NPMS to 
locate pipelines in communities and local jurisdictions; and (3) to 
issue additional guidance to owners and operators of pipeline 
facilities on the importance of providing system-specific information 
to emergency response agencies. PHMSA believes that such actions will 
address many of the concerns raised by the commenters.
Additional Safety Requirements for Non-HCA Areas
    PHMSA inquired as to whether additional safety measures should be 
developed for areas outside of HCAs.
Comments
    PHMSA received comments from three trade associations and one 
regulatory association. TransCanada Keystone, TxOGA, API-AOPL, and 
LMOGA indicated that no new requirements are necessary for areas 
outside of HCAs. The regulatory association, NAPSR, remarked that 
operators should be precluded from turning off in-line inspection 
sensors outside of an HCA when performing an integrity assessment under 
the IM regulations.
Response
    PHMSA agrees with the NAPSR comment and has likewise found that 
some operators do turn off inspection tools outside of HCAs. Therefore, 
PHMSA is proposing to require that operators perform periodic 
assessments of pipelines that are not already covered under the IM 
program requirements in Sec.  195.452. Promulgation of such a 
requirement will ensure that pipeline operators obtain the information 
necessary for the prompt detection and remediation of corrosion and 
other deformation anomalies (e.g., dents, gouges, and grooves) in all 
locations, not just in areas that could affect HCAs.
Inclusion of Major Road and Railway Crossings as HCAs
    PHMSA requested comment on the need to include major road and 
railway crossings as HCAs.
Comments
    Industry, three trade associations, three citizens' groups, one 
regulatory association, one government/municipality, and one citizen 
commented on this question.
    TransCanada Keystone, supported by the trade associations, API-
AOPL, TPA, TxOGA, and LMOGA, opposed including major roads and railway 
crossings as HCAs. The commenters offered several reasons to support 
that position (e.g., such a change would draw resources from other more 
high risk areas, non-HCA areas are already assessed and remediated, and 
there is no data to support such an action).
    Among the citizens' groups, PST stated that rail and major road 
crossings should be included. TWS and AKW stated that all 
transportation infrastructure, public lands, wetlands under the Clean 
Water Act (CWA), cultural, historical, archeological and recreation 
areas used for subsistence be included in HCAs.
    NAPSR also suggested that rail and major road crossings should be 
included. NAPSR urged PHMSA to consider the effect of a release on 
electric transmission facilities, gas pipelines, and railroads if major 
road and rail crossings were not to be included in HCAs. NAPSR would 
consider the effect of a release on electric transmission facilities, 
gas pipelines, railroads, etc., and would treat major road and rail 
crossings as HCAs for highly volatile liquids (HVLs) pipelines.
    The only government/municipality to comment on this question was 
DLA. DLA indicated that these structures should be included in HCAs.
    Citizen Coyle commented that major roadways should be HCAs because 
these areas could be affected by pipelines carrying HVLs that would 
produce poisonous clouds if released.
Response
    PHMSA is not proposing to designate major road and railway 
crossings as HCAs, but will consider whether the pipeline IM 
requirements should be applied to these areas when completing the study 
that Congress mandated under section 5 of the Pipeline Safety Act of 
2011. PHMSA notes that the pipelines at such crossings would be 
afforded additional protections under the other proposals made in this 
proceeding, including the requirements for the performance of periodic 
internal inspections and the use of leak detection systems.

C. Leak Detection Equipment and Emergency Flow Restricting Devices

    In the ANPRM, PHMSA asked for comment on whether to modify the 
current requirements part 195 for leak detection equipment and 
emergency flow restricting devices (EFRDs). Specifically, PHMSA asked 
whether
     The use of leak detection equipment should be required for 
hazardous liquid pipelines;
     The pipeline industry has developed any practices, 
standards, or leak detection technologies that should be incorporated 
by reference;
     Any industry practices or standards adequately address the 
relevant safety considerations;
     State regulations for leak detection should be adopted by 
regulation;
     Any new leak detection requirements should vary based on 
the sensitivity of the affected areas;
     The pipeline industry has developed standards or practices 
for the performance and location of EFRDs;
     The location of EFRDs should be specified by regulation; 
and
     Additional research and development is needed to 
demonstrate the suitability of any new leak detection technologies.
    As discussed below, PHMSA is considering requiring that all 
hazardous liquid pipelines have a system for detecting leaks and expand 
the use of EFRDs.
Expansion of Leak Detection Requirements
    In the ANPRM, PHMSA asked for comment on whether the agency should 
expand the leak detection requirements.
Comments
    Industry and trade associations generally supported expansion of 
the existing requirement in Sec.  195.452(i)(3) to most pipelines, but 
opposed including more-specific requirements in the regulations. API-
AOPL, TxOGA, TransCanada Keystone, and LMOGA supported extending leak 
detection requirements to all PHMSA-regulated pipelines, except for 
rural gathering lines.
    Citizens' groups supported enhanced leak detection requirements. 
TWS and PST opposed additional reliance on the current requirements in 
Sec.  195.452(i)(3), stating that this regulation includes no 
acceptance criteria and is virtually unenforceable. TWS further 
supported expanding leak detection requirements to all pipelines under 
PHMSA jurisdiction. NRDC indicated that leak detection requirements 
should be expanded to include a requirement that

[[Page 61625]]

worst-case-discharge-pumping times be based on historical shutdown 
times, rather than expected times. NRDC also said that operators should 
immediately contact first responders at the first sign of an issue. One 
citizen, Stec, suggested requiring use of ``smart coating'' with 
embedded conductors that would break to indicate coating damage and 
which could then trigger automatic response actions.
    The regulatory associations, DLA and MAWUC, supported expanded leak 
detection requirements. MAWUC suggested PHMSA require the use of leak 
detection equipment in all HCAs. DLA indicated that any new 
requirements should be delayed until better technology is available.
    The government/municipality, NSB, recommended leak detection 
requirements be expanded to all pipelines under PHMSA regulation. NSB 
encouraged adoption of more stringent leak detection requirements for 
sensitive offshore areas of the Beaufort and Chukchi seas.
Response
    As discussed earlier in this NPRM under the Background and 
Proposals section, PHMSA will propose to expand the leak detection 
requirements for HCA and non-HCA areas.
Consideration of New Industry Standards or Practices in Leak Detection
    PHMSA asked for public comment on whether any new industry 
standards or practices should be considered for adoption in part 195.
Comments
    API-AOPL, TxOGA, LMOGA, and TransCanada Keystone all indicated that 
the API-AOPL standard RP1165 (SCADA), RP 1167 (Pipeline Alarm 
Management), and RP1168 (Control Room Management) are good standards to 
utilize for leak detection systems. API-AOPL also pointed out that many 
new technologies are being developed and existing methodologies are 
continuously being improved for better leak detection capability; 
however, many of these new technologies have not been proven in service 
on cross-country pipelines.
    One citizens' group, NRDC, commented that new leak detection 
standards should address the additional demands posed by hazardous 
liquids. In particular, NRDC mentioned some hazardous liquids, such as 
diluted bitumen, have multiphase properties that can cause false 
alarms.
    The regulatory associations, NAPSR and DLA, both commented on new 
industry standards and practices in leak detection. NAPSR mentioned the 
new technology forward-looking infrared radar (FLIR) and encouraged 
PHMSA to consider using such new technologies. NAPSR reported that FLIR 
can detect changes in temperature near a pipeline from a winter leak, 
even under snow, and that it can be used from aerial patrols.
    DLA indicated that any leak detection standards should be third-
party validated and listed by the National Work Group on Leak Detection 
Evaluations (NWGLDE) and that leak detection in general for large 
volume pipelines is not very effective at this time.
Response
    The commenters only offered three specific industry standards or 
practices for consideration, and two of those standards, API RP1165 
(SCADA) and RP1168 (Control Room Management), are already incorporated 
into part 195 (see 49 CFR 195.3). PHMSA has concerns about the adequacy 
and enforceability of the third standard, API RP 1167 (Pipeline Alarm 
Management), and does not believe that it should be incorporated by 
reference at this time.
    As previously discussed, PHMSA is proposing to require that 
operators have a means for detecting leaks on all portions of a 
hazardous liquid pipeline system. Consideration of FLIR and any other 
emerging technologies would be required in evaluating what kinds of 
leak detection systems are appropriate for a particular pipeline. PHMSA 
will also be considering whether the use of specific leak detection 
technologies should be required in preparing the Secretary's report to 
Congress on that issue.
    PHMSA does not agree that third-party validation is a prerequisite 
to issuing new leak detection requirements for hazardous liquid 
pipelines. That limitation is not included in the Pipeline Safety Laws, 
and PHMSA does not believe that such action is necessary as a matter of 
administrative discretion.
Adequacy of Existing Industry Standards or Practices for Leak Detection
    PHMSA asked for public comment on whether any existing industry 
standards or practices for leak detection are adequate for adoption 
into part 195.
Comments
    TransCanada Keystone, TxOGA, LMOGA and API-AOPL submitted comments 
indicating that the current leak detection evaluations performed as a 
requirement of the IM program encompass many important factors for 
proper leak detection. PHMSA should allow for the implementation of 
recent regulatory changes, including the new Control Room Management 
(CRM) rule, before making any changes. NAPSR commented that all 
pipeline operators should, at a minimum, perform a tank balance 
periodically to detect leakage.
    NSB recommended that PHMSA adopt improved leak detection system 
standards and implement more stringent leak detection requirements for 
the sensitive offshore areas of the Beaufort and Chukchi seas. NSB 
stated that PHMSA should require: (1) Redundant leak detection systems 
for offshore pipelines; (2) All offshore pipeline leak detection 
systems to have the continuous capability to detect a daily discharge 
equal to not more than 0.5% of daily throughput within 15 minutes, and 
detect a pinhole leak within less than 24 hours; (3) All onshore 
pipeline leak detection systems to have the continuous capability to 
detect a daily discharge equal to not more than 1% of daily throughput 
within 15 minutes, and detect a pinhole leak within less than 24 hours; 
and (4) An initial performance test to verify leak detection accuracy 
upon installation and at regular intervals thereafter.
Response
    PHMSA agrees that the factors listed in Sec.  195.452(i)(3) are an 
appropriate basis for determining whether hazardous liquid pipelines 
have an adequate leak detection system and is proposing to use those 
factors as the basis for the requirements that would apply in all other 
locations. However, a December 31, 2007, report that PHMSA prepared in 
response to a mandate in the Pipeline Inspection, Protection, 
Enforcement, and Safety Act (PIPES Act) of 2006 (Pub. L. 109-468), 
confirmed that some operators had IM procedures that did not require 
the performance of a leak detection evaluation, and others had adopted 
an inadequate process for performing those evaluations. Operators are 
reminded that any failure to comply with part 195, including the leak 
detection requirements in Sec.  195.452(i)(3) and the proposed 
modifications to Sec. Sec.  195.134 and 195.444, increases both the 
likelihood and severity of pipeline accidents.
    PHMSA agrees that the new CRM requirements will improve the 
detection and mitigation of leaks on hazardous liquid pipeline systems, 
but does not agree that the implementation of improved leak detection 
requirements should be delayed solely on account of the recent issuance 
of those regulations. PHMSA will be monitoring the use of

[[Page 61626]]

leak detection systems by operators in complying with those 
requirements in determining if additional safety standards are needed.
Consideration of State Requirements/Regulations for Leak Detection
    Some states have established leak detection requirements for 
hazardous liquid pipeline systems. For example, the Alaska Department 
of Environmental Conservation (ADEC) has promulgated a regulation (18 
AAC 75.055) that states:
    (a) A crude oil transmission pipeline must be equipped with a leak 
detection system capable of promptly detecting a leak, including
    (1) if technically feasible, the continuous capability to detect a 
daily discharge equal to not more than one percent of daily throughput;
    (2) flow verification through an accounting method, at least once 
every 24 hours; and
    (3) for a remote pipeline not otherwise directly accessible, weekly 
aerial surveillance, unless precluded by safety or weather conditions.
    (b) The owner or operator of a crude oil transmission pipeline 
shall ensure that the incoming flow of oil can be completely stopped 
within one hour after detection of a discharge.
    (c) If above ground oil storage tanks are present at the crude oil 
transmission pipeline facility, the owner or operator shall meet the 
applicable requirements of 18 AAC 75.065, 18 AAC 75.066, and 18 AAC 
75.075.
    (d) For facility oil piping connected to or associated with the 
main crude oil transmission pipeline the owner or operator shall meet 
the requirements of 18 AAC 75.080.
    Operators who install online leak detection systems can also 
receive a reduction in the volume of crude oil that must be used in 
complying with Alaska's oil spill response planning requirements (18 
AAC 75.436(c)(3)).
    The State of Washington has also prescribed leak detection 
requirements for hazardous liquid pipelines (WAC 480-75-300). Those 
requirements, which are administered by the Washington Utilities and 
Transportation Commission (WUTC), state:
    (1) Pipeline companies must rapidly locate leaks from their 
pipeline. Pipeline companies must provide leak detection under flow and 
no flow conditions.
    (2) Leak detection systems must be capable of detecting an eight 
percent of maximum flow leak within fifteen minutes or less.
    (3) Pipeline companies must have a leak detection procedure and a 
procedure for responding to alarms. The pipeline company must maintain 
leak detection maintenance and alarm records.
Comments
    PHMSA received comments from several trade associations and one 
citizens' group on state requirements for leak detection systems. API-
AOPL indicated that pipeline configuration and operational factors vary 
by geographic location, and that other variability exists, including 
fluid or product differences, batching, and other operational 
conditions. Due to these factors, any type of prescriptive approach to 
standards for leak detection is difficult to achieve and would be 
better served using a performance standard. CRAC noted that multi-phase 
lines are more susceptible to internal corrosion, and that state 
regulations do not require IM or leak detection.
    NAPSR and DLA also commented. NAPSR encouraged PHMSA to allow the 
states to set minimum leak detection criteria for intrastate pipelines. 
DLA opposed development of criteria based on state requirements and 
suggested that new requirements be third-party validated and listed by 
NWGLDE.
Response
    PHMSA favors the use of performance-based safety standards and 
believes that the regulations adopted by ADEC and WUTC show that 
certain minimum threshold requirements can be established for leak 
detection systems. PHMSA will be considering these and other similar 
regulations in an evaluation of leak detection systems.
    With regard to NAPSR's comment, section 60104(c) of the Pipeline 
Safety Laws allows states that have submitted a current certification 
to adopt additional or more stringent safety standards for intrastate 
hazardous liquid pipeline facilities, so long as those requirements are 
compatible with the minimum federal safety standards. PHMSA has 
prescribed mandatory leak detection requirements for hazardous liquid 
pipelines that could affect HCAs and is proposing to make those 
requirements applicable to all pipelines subject to part 195. States 
that have submitted a current certification can establish additional or 
more stringent leak detection standards for intrastate hazardous liquid 
pipeline facilities, subject to the statutory compatibility 
requirement.
    PHMSA does not agree that third-party validation is a prerequisite 
to issuing new leak detection requirements for hazardous liquid 
pipelines. That limitation is not included in the Pipeline Safety Laws, 
and PHMSA does not believe that such action is necessary as a matter of 
administrative discretion.
Different Leak Detection Requirements for Sensitive Areas
    Section 195.452(i)(3) contains a mandatory leak detection 
requirement for hazardous liquid pipelines that could affect an HCA. 
That regulation requires operators to consider several factors (i.e., 
the length and size of the pipeline, type of product carried, proximity 
to the HCA, the swiftness of leak detection, location of nearest 
response personnel, leak history, and risk assessment results) in 
selecting an appropriate leak detection system.
Comments
    PHMSA received many comments in response to whether there should be 
different leak detection requirements for sensitive areas. The trade 
associations, TxOGA and LMOGA, supported API-AOPL's comments that most 
leak detection methods cannot target specific areas. API-AOPL further 
stated that leak detection for sensitive areas can be achieved through 
comprehensive risk-based evaluation, but that external monitoring is 
too invasive and is not yet proven or cost effective.
    The regulatory associations, government/municipalities, and 
citizens all supported increased leak detection requirements for 
sensitive areas. The regulatory association, NAPSR, mentioned the use 
of FLIR for sensitive areas and stated that special actions beyond 
patrols should be required for sensitive areas. DLA indicated leak 
detection standards should be third-party validated. MAWUC and a 
citizen, Coyle, recommended requiring external leak detectors in HCAs. 
Coyle would also require external leak detectors for above-ground 
pipelines transporting highly volatile liquids. NSB encouraged PHMSA to 
adopt improved leak detection standards and implement more stringent 
requirements for sensitive areas.
Response
    PHMSA believes that the leak detection requirements in Sec.  
195.452(i)(3) can provide adequate protection for sensitive areas and 
is proposing to use those requirements as the basis for establishing 
requirements that would apply to hazardous liquid pipelines in all 
other locations. Under the current and proposed regulations, operators 
are required to consider several factors in selecting an appropriate 
leak detection system, including the characteristics and history of the 
affected pipeline, the capabilities of the available leak

[[Page 61627]]

detection systems, and the location of emergency response personnel. 
PHMSA commissioned Kiefner and Associates, Inc., to perform a study on 
leak detection systems used by hazardous liquid operators. That study, 
titled ``Leak Detection Study,'' \4\ was completed on December 10, 
2012, and was submitted to Congress on December 27, 2012. PHMSA is 
considering, in a different rulemaking activity, whether to adopt 
additional or more stringent requirements for sensitive areas in 
response to this study.
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Key Issues for New Leak Detection Standards
Comments
    The trade associations, TxOGA, LMOGA, and API-AOPL, supported by an 
industry commenter, TransCanada Keystone, stated that PHMSA should 
identify issues that might adversely affect response times, including 
limiting the consequences for first responder deployment and allowing 
for the withdrawal of erroneous leak notifications. NAPSR, the only 
regulatory association to comment, found that any new standards should 
consider detection of small leaks in HCAs, maintenance, accuracy, 
transient conditions, system capabilities, and alarm management.
    Three government/municipalities commented on this issue. DLA stated 
that any standards should address sensitivity, probability of false 
alarms, minimum leak detection capabilities, frequency, and be based on 
leak detection technology. MAWUC supported more stringent reporting and 
repair requirements. NSB indicated that PHMSA should require redundant 
leak detection systems for offshore lines. NSB also indicated the 
technology available for leak detection systems is vastly improved and 
industry should bear the burden to utilize these systems.
Response
    The Pipeline Safety Laws contain a number of general factors that 
must be considered in prescribing new safety standards, including the 
reasonableness of the standard, the estimated benefits and costs, and 
the views and recommendations of the Technical Hazardous Liquid 
Pipeline Safety Standards Committee (49 U.S.C. 60102(b)). The Pipeline 
Safety Laws also contain specific factors that must be considered in 
prescribing certain safety standards, such as for smart pigs (49 U.S.C. 
60102(f)) or low-stress hazardous liquid pipelines (49 U.S.C. 
60102(k)).
    In the case of leak detection, Congress has enacted prior statutory 
mandates that required the Secretary to survey and assess the need for 
additional safety standards. PHMSA and its predecessor agency, RSPA, 
complied with those mandates by producing two reports and promulgating 
additional safety standards for leak detection systems. Congress 
enacted a similar provision in section 8 of the Pipeline Safety Act of 
2011, including a requirement that the Secretary submit a report to 
Congress that provides an analysis of the technical limitations of 
current leak detection systems and the practicability, safety benefits, 
and adverse consequence of establishing additional standards for the 
use of such systems.
    The commenters identified several issues that should be considered 
in establishing new leak detection standards, including the need to 
minimize false alarms, to set appropriate volumetric thresholds, and to 
encourage the use of best available technologies.
Statistical Analyses of Leak Detection Requirements
    PHMSA asked the public to comment on the availability of statistics 
on whether existing practices or standards on leak detection have 
contributed to reduced spill volumes and consequences.
Comments
    One response submitted by API-AOPL, supported by TransCanada 
Keystone, LMOGA, and TxOGA, stated that the association was unaware of 
any recent statistics in regard to this topic. API-AOPL further 
indicated that PHMSA should allow time for recent regulatory changes to 
take effect on the regulated population.
Response
    PHMSA's December 2007 report on leak detection systems noted that 
from 1997 to 2007 ``the median volume lost from hazardous liquid 
pipeline accidents dropped by more than half, from 200 to less than 100 
barrels,'' and that ``the number of accidents declined by over a 
third.'' The report attributed that positive trend to the 
implementation of the pipeline IM requirements in Sec.  195.452. 
However, the report also indicated that all of the available leak 
detection technologies have strengths and weakness, that some are only 
suitable for use on particular pipeline systems, and that establishing 
safety standards would require consideration of a number of factors.
Consideration of Industry Practices or Standards for Location of EFRDs
    Part 195 requires that EFRDs be considered as potential mitigation 
measure on pipeline segments that could affect HCAs. In terms of 
Sec. Sec.  195.450 and 195.452 the definition for check valve means a 
valve that permits fluid to flow freely in one direction and contains a 
mechanism to automatically prevent flow in the other direction. 
Likewise, remote control valve or RCV means any valve that is operated 
from a location remote from where the valve is installed. The RCV is 
usually operated by the supervisory control and data acquisition 
(SCADA) system. The linkage between the pipeline control center and the 
RCV may be by fiber optics, microwave, telephone lines, or satellite.
    Section 195.452(i)(4) further states that if an operator determines 
that an EFRD is needed on a pipeline segment to protect a high 
consequence area in the event of a hazardous liquid pipeline release, 
an operator must install the EFRD. In making this determination, an 
operator must, at least, consider the following factors--the swiftness 
of leak detection and pipeline shutdown capabilities, the type of 
commodity carried, the rate of potential leakage, the volume that can 
be released, topography or pipeline profile, the potential for 
ignition, proximity to power sources, location of nearest response 
personnel, specific terrain between the pipeline segment and the high 
consequence area, and benefits expected by reducing the spill size.
    RSPA adopted the EFRD requirements in Sec. Sec.  195.450 and 
195.452 in a December 2000 final rule December 1, 2000, (65 FR 75378). 
Part 195 does not require that EFRDs be used on pipelines outside of 
HCAs, but Sec.  195.260 does require that valves be installed at 
certain locations.
    Congress included additional requirements for the use of automatic 
and remote-controlled shut-off valves in section 4 of the Pipeline 
Safety Act of 2011. That provision requires the Secretary, if 
appropriate and where economically, technically, and operationally 
feasible, to issue regulations for the use of automatic and remote-
controlled shut-off valves on transmission lines that are newly 
constructed or entirely replaced. The Comptroller General is also 
required to perform a study on the effectiveness of these valves and to 
provide a report to Congress within one year of the date of the 
enactment of that legislation. PHMSA commissioned a study titled 
``Studies for the Requirements of

[[Page 61628]]

Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids 
and Natural Gas Pipelines With Respect to Public and Environmental 
Safety,'' \5\ to help provide input on regulatory considerations 
regarding the feasibility and effectiveness of automatic and remote-
control shutoff valves on hazardous liquid and natural gas transmission 
lines. The study was completed by the Oak Ridge National Laboratory on 
October 31, 2012, and it was submitted to Congress on December 27, 
2012. PHMSA is using considerations from this study as it drafts a 
rulemaking titled ``Amendments to Parts 192 and 195 to require Valve 
installation and Minimum Rupture Detection Standards.''
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Comments
    PHMSA received comment on this issue from industry and trade 
associations. API-AOPL, TxOGA, LMOGA, and TransCanada Keystone reported 
that no industry standards currently address EFRD use, although ASME 
B31.4, ``Pipeline Transportation Systems for Liquid Hydrocarbons and 
Other Liquids'' (2009), addresses mainline valves and requires remote 
operation and/or check valves in some instances. ASME B31.4 (2009) also 
has guidelines for mainline valves and requires remote and check 
valves, but is not currently incorporated by reference into part 195. 
Section 195.452 does require that operators identify the need for 
additional preventive and mitigation measures.
Response
    PHMSA is studying issues concerning the development of additional 
safety standards for the use of EFRDs. PHMSA will consider the industry 
standards mentioned by the commenters, as well as the results of the 
September 1996 Volpe Report, the December 2007 Leak Detection Study, 
and the 2012 Oak Ridge National Laboratory study, for the purposes of 
any future rulemaking on the topic.
Adequacy of Existing Industry Practices or Standards for EFRDs
    PHMSA asked for comment on the adequacy of existing industry 
practices or standards for EFRDs.
Comments
    API-AOPL, TxOGA, LMOGA, and TransCanada Keystone stated that there 
is no current industry standard that sets a maximum spill volume or 
activation timing due to the widespread variation in pipeline dynamics; 
therefore, it would be difficult to establish a one-size-fits-all 
maximum spill volume requirement. API-AOPL suggests PHMSA should focus 
on prevention and response rather than spill size reduction through 
EFRDs.
Response
    Section 195.452(i)(4) contains a requirement for the use of EFRDs 
on hazardous liquid pipelines that could affect an HCA. PHMSA agrees 
with the commenters that oil spill prevention and response are 
important to ensuring the safety of hazardous liquid pipelines, and 
believes that the appropriate use of EFRDs could be complementary to 
these efforts.
Consideration of Additional Standards Specifying the Location of EFRDs
    Part 195 requires that EFRDs be considered as potential mitigation 
measure on pipeline segments that could affect HCAs, but it does not 
specify any particular location for the use of those devices. Operators 
must perform a risk analysis in determining whether and where to 
install EFRDs for such lines. Part 195 does not require that EFRDs be 
used on pipelines outside of HCAs. In the ANPRM, PHMSA asked for 
comment on whether additional standards should be developed to specify 
the location for EFRDs.
Comments
    PHMSA received comments from four trade associations, one industry 
operator, and one regulatory association regarding prescriptive 
location of EFRDs. API-AOPL, TransCanada Keystone, LMOGA, and TxOGA 
indicated PHMSA should not specify location of EFRD placement for the 
reasons provided in response to previous questions. TPA agreed that no 
general criteria beyond those in existing regulations are appropriate 
because decisions on EFRD placement are driven by local factors. NAPSR 
supported the comments of the trade associations.
Response
    PHMSA recognizes the commenters' concerns about mandating the 
installation of EFRDs in particular locations, but notes that other 
provisions in part 195 require that valves and other safety devices be 
installed in certain areas.
Mandated Use of EFRDs in All Locations
    PHMSA requested comment on mandated use of EFRDs in all locations 
under PHMSA jurisdiction.
Comments
    API-AOPL, TransCanada Keystone, LMOGA, and TxOGA indicated that a 
requirement to place EFRDs at predetermined locations or fixed 
intervals would be arbitrary, costly, and potentially counterproductive 
to pipeline safety. They noted that not all valves are mainline valves, 
and that a requirement for all valves to be remote would cause 
confusion. Many valves are at manned facilities. Some EFRDs are check 
valves, which are not amenable to remote control. API-AOPL noted that 
costs related to providing remote operation would vary based on 
proximity to power and communications, but that a December 2010 study 
by the Congressional Research Service estimated retrofit costs of $40K 
to $1.5M per valve. NAPSR agreed with the comments supplied by the 
trade associations and TransCanada Keystone. Finally, NSB stated EFRDs 
should be required on all pipelines PHMSA regulates with specific 
instruction on when and where EFRDs need to be utilized.
Response
    PHMSA recognizes the commenters' concerns about mandating the 
installation of EFRDs in all locations and plans on continuing to study 
this issue.
Additional Research for Leak Detection
    PHMSA requested comment regarding what leak detection technologies 
or methods require further research and development to demonstrate 
their efficacy.
Comments
    PHMSA received no comments in response to this question.

D. Valve Spacing

Valve Spacing
    The ANPRM asked whether PHMSA should repeal or modify the valve 
spacing requirements in part 195. Specifically, the ANPRM asked:
     For information on the average distance between valves;
     Whether valves are manually operated or remotely 
controlled;
     Whether additional standards should be adopted for 
evaluating valve spacing and location;
     Whether the maximum permissible distance between valves 
should be specified by regulation;
     Whether to adopt additional valve spacing requirements for 
hazardous liquid pipelines near HCAs;
     Whether additional valve spacing requirements should be 
adopted to protect narrower bodies of water;

[[Page 61629]]

     Whether all valves should be remotely controlled; and
     What the cost impact would be from requiring the 
installation of certain types of valves.

As discussed below, PHMSA is not proposing to adopt any additional 
standards for valve spacing, but will be considering that issue in 
complying with the various mandates in the Pipeline Safety Act of 2011.

    Part 195 contains general construction requirements for valves. 
Specifically, Sec.  195.258 provides that each valve must be installed 
in a location that is accessible to authorized employees and protected 
from damage or tampering. This section further states that submerged 
valves located offshore or in inland navigable waters must be marked, 
or located by conventional survey techniques, to facilitate quick 
location when operation of the valve is required.
    PHMSA pipeline safety regulations found in section 195.260 indicate 
that a valve must be installed at certain locations. The locations 
named include on the suction end and the discharge end of a pump 
station or a breakout storage tank area in a manner that permits 
isolation of the tank area from other facilities and on each mainline 
at locations along the pipeline system that will minimize damage or 
pollution from accidental hazardous liquid discharge, as appropriate 
for the terrain in open country, for offshore areas, or for populated 
areas. Three additional requirements for valve location in section 
195.260 include each lateral takeoff from a trunk line, on each side of 
a water crossing that is more than 100 feet (30 meters) wide from high-
water mark to high-water mark and on each side of a reservoir holding 
water for human consumption. The Department adopted these regulations 
in an October 1969 final rule October 4, 1969, (34 FR 15475).
    As discussed in section 3, part 195 requires the use of EFRDs as a 
potential mitigation measure on pipeline segments that could affect 
HCAs. As also discussed in section 3, Congress included new provisions 
for the use of automatic and remote-controlled shut-off valves and leak 
detection systems in the Pipeline Safety Act of 2011.
Information on Average Distance Between Valves and Manual or Remote 
Operation
    PHMSA asked the public to provide information on the average 
distance between valves and whether such valves are manually operated 
or remotely controlled.
Comments
    The commenters did not provide any data on the average distance 
between valves, but did provide general information on valve spacing, 
location, and type. The commenters further noted that ASME B31.4, a 
consensus industry standard, includes a minimum valve spacing 
requirement of 7.5 miles for liquefied petroleum gas (LPG) and 
anhydrous ammonia pipelines in populated areas.
    Specifically, API-AOPL, LMOGA, TxOGA, and TransCanada Keystone 
stated that valve spacing varies, that most mainline valves are 
manually operated, that check valves are used in certain cases, and 
that some remotely controlled valves had been added as a result of the 
IM requirements. API-AOPL also commented that ASME B31.4 provides 
additional requirements for LPG and anhydrous ammonia in populated 
areas, including a 7.5-mile spacing requirement for valves, but noted 
that PHMSA had not incorporated this version of B31.4 into part 195. 
NAPSR stated that proper valve location is more important than distance 
placement.
Response
    Part 195 requires the installation of valves at certain locations, 
including pump stations, breakout tanks, mainlines, lateral lines, 
water crossings, and reservoirs. These requirements are generally 
directed toward achieving a particular result (e.g., isolation of a 
facility, minimization of damage or pollution, etc.) and do not mandate 
that valves be installed at specific distances.
    Part 195 does not prescribe whether manual or remotely controlled 
valves must be installed at particular locations, but does require 
consideration of check valves and remotely controlled valves under the 
EFRD requirements for pipelines that could affect an HCA. Section 4 of 
the Pipeline Safety Act of 2011 includes new requirements for 
evaluating and issuing additional regulations for the use of the 
automatic and remote-controlled shut-off valves.
    PHMSA is not proposing to make any changes to the current valve 
spacing requirements at this time. A coordinated analysis will ensure 
that these issues are addressed in a way that maximizes the potential 
benefits and minimizes the potential burdens imposed by any new leak 
detection and valve spacing standards.
Adoption of Additional Standards for Valve Spacing and Location
    PHMSA asked for comment on the adoption of additional standards for 
valve spacing and location.
Comments
    TransCanada Keystone, API-AOPL, TxOGA, and LMOGA stated that the 
standards in Sec. Sec.  195.260 and 195.452 are satisfactory. NAPSR 
supported the comments of API-AOPL. NSB recommended that DOT adopt 
standards for pipeline operators to use in evaluating valve spacing and 
location and identifying the maximum distance between valves.
Response
    PHMSA is not proposing to adopt any additional standards for valve 
spacing and locations, but will be considering that issue in complying 
with the various mandates in the Pipeline Safety Act of 2011. PHMSA 
held a public meeting/workshop on valve spacing and locations on March 
28, 2012. Information from this workshop was used in Oak Ridge National 
Laboratory's study, completed October 31, 2012, titled: ``Studies for 
the Requirements of Automatic and Remotely Controlled Shutoff Valves on 
Hazardous Liquids and Natural Gas Pipelines with Respect to Public and 
Environmental Safety'' \6\ to help determine the need for additional 
valve and location standards.
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Additional Standards for Specifying the Maximum Distance Between Valves
    PHMSA asked for public comment on whether part 195 should specify 
the maximum permissible distance between valves.
Comment
    API-AOPL, TxOGA, LMOGA, TransCanada Keystone, and TPA opposed such 
a requirement and stated that valve spacing should be based on 
conditions and terrain. NAPSR also supported this position. NSB and 
MAWUC recommended the DOT adopt specific valve spacing standards. MAWUC 
stated that the criteria for valve spacing should be developed, but 
that the precise location of valves should not be made publicly 
available.
Response
    Similarly, PHMSA is not proposing to adopt any additional standards 
for valve spacing at this time. PHMSA will be studying this issue and 
may make proposals concerning this topic in a later rulemaking.

[[Page 61630]]

Additional Requirements for Valve Spacing Near HCAs Beyond Those 
Required for EFRDs
    PHMSA asked for public comment on whether part 195 should contain 
additional requirements for valve spacing in areas near HCAs beyond 
what is already required in Sec.  195.452(i)(4) for EFRDs.
Comments
    NSB encouraged PHMSA to adopt additional requirements for these 
areas. Taking a contrary position, API-AOPL, LMOGA, TxOGA, NAPSR, and 
TransCanada Keystone indicated that the current requirements adequately 
address the need for EFRDs and allow operators to assess the specific 
risks on each individual pipeline that could affect an HCA.
Response
    PHMSA does not propose to make any changes to the regulations 
concerning the valve spacing at this time. PHMSA will be studying this 
issue and may make proposals concerning this topic in a later 
rulemaking.
Modifying the Scope of 49 CFR 195.260(e) To Include Narrower Bodies of 
Water
    Section 195.260(e) requires the installation of a valve ``[o]n each 
side of a water crossing that is more than 100 feet (30 meters) wide 
from high-water mark to high-water mark unless the Administrator finds 
in a particular case that valves are not justified.'' The Department 
adopted that requirement in an October 1969 final rule October 4, 1969, 
(34 FR 15475) after adding the provision that allows the Administrator 
to find that the installation of a valve is not justified in specific 
cases. Such a finding requires the filing of a petition with the 
Administrator under 49 CFR 190.9.
Comments
    API-AOPL, TxOGA, LMOGA, and TransCanada Keystone indicated that the 
current water crossing requirements are adequate, but that PHMSA could 
improve the regulation by allowing a risk-based approach for valve 
placement at water crossings and adding an exclusion for carbon dioxide 
pipelines.
    TWS stated that PHMSA should require valves for waterways that are 
at least 25-feet in width and all feeder streams and creeks leading to 
such waterways. NSB supported the view of TWS and indicated the current 
100-foot threshold for waterways should be reduced to 25 feet.
Response
    As mentioned previously, PHMSA is proposing that all pipelines be 
inspected after extreme weather events or natural disasters. This is a 
natural extension of IM and ensures continued safe operations of the 
pipeline after abnormal operating conditions. Past events have strongly 
demonstrated that inspections after these events do prevent pipeline 
incidents from occurring. PHMSA is also proposing to require that all 
hazardous liquid pipelines have leak detection systems; that pipelines 
in areas that could affect HCAs be capable of accommodating ILIs within 
20 years, unless the basic construction of the pipeline will not permit 
such an accommodation; that periodic assessments be performed of 
pipelines that are not already receiving such assessments under the IM 
program requirements; and that modified repair criteria be applied to 
pipelines in all locations. PHMSA will comply with the applicable 
provisions in the Pipeline Safety Act of 2011 before adopting any of 
these proposals in a final rule.
Adopting Safety Standards That Require All Valves To Be Remotely 
Controlled
    PHMSA asked the public to comment on whether part 195 should 
include a requirement mandating the use of remotely-controlled valves 
in all cases.
Comments
    API-AOPL, LMOGA, and TxOGA stated that PHMSA should not require 
remotely controlled valves in all cases. API-AOPL indicated that such a 
requirement would cause confusion as to which valves need to be 
operated manually, burden the industry with additional costs, and 
provide minimal safety benefits. API-AOPL submitted that the costs of 
retrofitting a valve to be remotely controlled varies widely from 
$40,000 to $1.5 million per valve as indicated in a recent report 
issued by the Congressional Research Service on pipeline safety and 
security. TPA further stated that the benefits of such requirements are 
dependent on local factors, and that additional requirements would add 
to pipeline system complexity and increase the probability of failure. 
Similarly, NAPSR stated that remote control valves should not be 
required, but that PHMSA should consider performance language for 
maximum response time to operate manual valves.
    MAWUC indicated that PHMSA should consider requiring all valves to 
be remotely controlled, but that its decision should be based on an 
analysis of benefits and risks. NSB supported the use of remotely 
controlled valves in all instances. Coyle, a citizen, commented that 
PHMSA should promulgate regulatory language requiring remotely 
controlled valves for poison inhalation hazard pipelines.
Response
    PHMSA notes that a risk-assessment must be performed in developing 
any new safety standards for the use of remotely controlled valves, and 
that any such standards will only be proposed upon a reasoned 
determination that the benefits justify the costs.
Requiring Installation of EFRDs To Protect HCAs
    Section 195.452(i)(4) does not require the installation of an EFRD 
on all pipeline segments that could affect HCAs. Rather, it states that 
``[i]f an operator determines that an EFRD is needed on a pipeline 
segment to protect a high consequence area in the event of a hazardous 
liquid pipeline release, an operator must install the EFRD.'' It also 
states that an operator must at least consider a list of factors in 
making that determination.
Comments
    API-AOPL, LMOGA, TxOGA and TransCanada Keystone stated that Sec.  
192.452 already requires EFRDs to be installed to protect a HCA if the 
operator finds, through a risk assessment, that an HCA is threatened. 
MAWUC commented that EFRDs should be required if they can limit a 
spill. Likewise, NSB supported the use of EFRDs for HCAs.
Response
    PHMSA does not propose to make any changes to the regulations 
concerning the use of EFRDs at this time. PHMSA will be studying this 
issue and may make proposals concerning this topic in a later 
rulemaking.
Determining the Applicability of New Valve Location Requirements
    In the ANPRM, PHMSA asked for public comment on how the agency 
should apply any new valve location requirements that are developed for 
hazardous liquid pipelines.
Comments
    The trade association, API-AOPL, supported by TransCanada Keystone, 
LMOGA, and TxOGA, indicated that valve spacing requirements should not 
be changed, and that delineating new construction for any type of 
grandfathering purpose would be difficult and confusing. Requiring 
retrofitting of existing lines to meet any

[[Page 61631]]

type of new requirement would be expensive for industry, create 
environmental impacts, potential construction accidents, and may cause 
interruption of service.
    The regulatory association, NAPSR, suggested that exemptions to new 
valve location requirements should be based on the consequence of 
failure. Particular attention should be paid to spills into water as 
even a small spill can create a large problem.
    Two government/municipalities commented. MAWUC indicated that there 
should be no waivers for valve spacing in HCAs due to the importance 
and interconnectivity of water supplies. NSB recommended that any new 
valve locations or remote actuation regulation be applied to new 
pipelines or existing pipelines that are repaired.
Response
    PHMSA will continue to study valve spacing and automatic valve 
placement and may address these issues in a future rulemaking.

E. Repair Criteria Outside of HCAs

Repair Criteria
    The ANPRM asked for public comment on whether to extend the IM 
repair criteria in Sec.  195.452(h) to pipeline segments that are not 
located in HCAs. Specifically, the ANPRM asked ``Whether the IM repair 
criteria should apply to anomalous conditions discovered in areas 
outside of HCAs; whether the application of the IM repair criteria to 
non-HCA areas should be tiered on the basis of risk; what schedule 
should be applied to the repair of anomalous conditions discovered in 
non-HCA areas; whether standards should be specified for the accuracy 
and tolerance of inline inspection (ILI) tools; and whether additional 
standards should be established for performing ILI inspections with 
``smart pigs''.
    As discussed below, PHMSA is proposing to modify the provisions for 
making pipeline repairs. Additional conservatism will be incorporated 
into the existing IM repair criteria and an adjusted schedule for 
making immediate and non-immediate repairs will be established to 
provide greater uniformity. These criteria will also be made applicable 
to all pipelines, with an extended timeframe for making repairs outside 
of HCAs.
Application of IM Repair Criteria to Anomalous Conditions Discovered 
Outside of HCAs
    In the ANPRM, PHMSA asked for comment on whether the IM repair 
criteria should apply to anomalous conditions discovered in areas 
outside of HCAs.
Comments
    API-AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, 
stated that the repair criteria in or outside of HCAs should be the 
same. Likewise, the citizens' groups TWS and AKW echoed the comments of 
API-AOPL and further recommended that a phased-in time period should be 
utilized. NSB commented that anomalous conditions found during 
inspection in non-HCA areas should trigger expedited repair times.
Response
    Section 195.452(h) specifies the actions that an operator must take 
to address integrity issues on hazardous liquid pipelines that could 
affect an HCA in the event of a leak or failure. Those actions include 
initiating temporary and long-term pressure reductions and evaluating 
and remediating certain anomalous conditions (e.g., metal loss, dents, 
corrosion, cracks, gouges, grooves, and other any condition that could 
impair the integrity of the pipelines). Depending on the severity of 
the condition, such actions must be taken immediately, within 60 days, 
or within 180 days of the date of discovery.
    Section 5 of the Pipeline Safety Act of 2011 requires the Secretary 
to perform an evaluation to determine if the IM requirements should be 
extended outside of and to submit a report to Congress with the result 
of that review. The Secretary is authorized to collect data for 
purposes of completing the evaluation and report to Congress. Section 5 
also prohibits the issuance of any final regulations that would expand 
the IM requirements during a subsequent Congressional review period, 
subject to a savings clause that permits such action if a condition 
poses a risk to public safety, property, or the environment or is an 
imminent hazard and the regulations in question will address that risk 
or imminent hazard.
    PHMSA is proposing to make certain modifications to the IM repair 
criteria and to establish similar repair criteria for pipeline segments 
that are not located in HCAs. Specifically, the repair criteria in 
Sec.  195.452(h) would be amended to:
     Categorize bottom-side dents with stress risers 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.

PHMSA is also proposing to adopt new requirements in Sec.  195.422 that 
would: Apply the criteria in the immediate repair category in Sec.  
195.452(h) and Establish an 18-month repair category for hazardous 
liquid pipelines that are not subject to the IM requirements.

    These changes will ensure that immediate action is taken to 
remediate anomalies that present an imminent threat to the integrity of 
hazardous liquid pipelines in all locations. Many anomalies that would 
not qualify as immediate repairs under the current criteria will meet 
that requirement as a result of the additional conservatism that will 
be incorporated into the burst pressure calculations. The new 
timeframes for performing other repairs will allow operators to 
remediate those conditions in a timely manner while allocating 
resources to those areas that present a higher risk of harm to the 
public, property, and the environment.
Use of a Tiered, Risk-Based Approach for Repairing Anomalous Conditions 
Discovered Outside of HCAs
    In the ANPRM, PHMSA asked for comment on whether the application of 
the IM repair criteria to non-HCA areas should be tiered on the basis 
of risk.
Comments
    API-AOPL, LMOGA, TPA, TxOGA, and TransCanada Keystone commented 
that PHMSA should not impose any sort of tiering to repair criteria 
because that is already inherent to the IM program. Scheduling 
flexibility would minimize disruption to the affected public, as well 
as the overall environmental impact, by preventing multiple excavation 
work on a given property. Requiring additional risk tiering of 
anomalies would not reduce safety risks to the public.
    NAPSR, in contrast, commented that tiering should be utilized for 
repair criteria inside or outside of HCAs. NSB also indicated that risk 
tiering should be used. MAWUC supported risk tiering based on 
preselected criteria for HCAs.
Response
    As previously discussed, PHMSA is proposing to apply new repair 
criteria for anomalous conditions discovered on hazardous liquid 
pipelines that are not located in HCAs. PHMSA is also proposing to 
establish two timeframes for performing those repairs: immediate repair 
conditions and 18-month repair conditions. If adopted as proposed, 
these changes will ensure the prompt remediation of anomalous 
conditions on all hazardous liquid pipeline segments, while allowing 
operators to allocate

[[Page 61632]]

their resources to those areas that present a higher risk of harm to 
the public, property, and the environment.
Updating of Dent With Metal Loss Repair Criteria
    Section 195.452(h) contains the criteria for repairing dents with 
metal loss on hazardous liquid pipeline segments that could affect an 
HCA in the event of a leak or failure. PHMSA asked for comment on 
whether advances in ILI tool capability justified an update in the 
dent-with-metal-loss repair criteria.
Comments
    API-AOPL, LMOGA, TxOGA, and TransCanada Keystone indicated that the 
anticipated update to API 1160 will contain proposals to update the 
dent-with-metal-loss repair criterion. API-AOPL intends to support 
these proposals with data resulting from analyses of member company's 
experience measuring and characterizing metal loss in dents.
    NAPSR encouraged PHMSA not to make the current standards less 
stringent even for dents without metal loss, citing a recent bottom 
side dent less than 6 inches that failed. NAPSR recommended 
strengthening the repair criteria for bottom-side dents in areas of 
heavy traffic or near swamps/bogs or in clay soils.
Response
    As previously discussed, PHMSA is proposing to categorize bottom-
side dents with stress risers as an immediate repair condition and to 
require immediate repairs when calculated burst pressure is less than 
1.1 times MOP. These changes should ensure the prompt and effective 
remediation of anomalous conditions on all pipeline segments. With 
respect to API 1160, PHMSA will consider incorporating the 2013 edition 
in a future rulemaking.
Adoption of Explicit Standards To Account for Accuracy of ILI Tools
    PHMSA requested comment on whether to adopt an explicit standard to 
account for the accuracy of ILI tools when comparing ILI data with 
repair criteria.
Comments
    API-AOPL supports PHMSA's adoption of API 1163, the ``In-Line 
Inspection Systems Qualification Standard''. That standard includes a 
System Results Verification section, which describes methods to verify 
that the reported inspection results meet, or are within, the 
performance specification for the pipeline being inspected. That 
standard also requires that inconsistencies uncovered during the 
process validation be evaluated and resolved.
    NAPSR supports the adoption of a standard because the IM process 
already is considering tool accuracy during the selection process and 
suggests revising the regulations to provide minimum standards of 
expected accuracy.
Response
    In reviewing IM inspection data, PHMSA discovered that some 
operators were not considering the accuracy (i.e., tolerance) of ILI 
tools when evaluating the results of the tool assessments. As a result, 
random variation within the recorded data led to both overcalls (i.e., 
an anomaly was identified to be more extreme than it actually was) and 
under calls. Over calls are conservative, resulting in repair of some 
anomalies that might not actually meet repair criteria. Under calls are 
not and can result in anomalies that exceed specified repair criteria 
going un-remediated. Based on our review of inspection data, PHMSA has 
concluded that operators should be explicitly required to consider the 
accuracy of their ILI tools.
    Specifically, under the proposed amendment to Sec.  
195.452(c)(1)(i) and the new provisions in Sec.  195.416, operators 
will be required to consider tool tolerance and other uncertainties in 
evaluating ILI results for all hazardous liquid pipeline segments. Tool 
accuracy should include excavation findings and usage of unity plots of 
inline tool and excavation findings. When combined with the proposed 
changes to the repair criteria, the proposed tool tolerance requirement 
will ensure the prompt detection and remediation of anomalous 
conditions on all hazardous liquid pipelines. With respect to API 1163, 
as of January 2013, PHMSA is required by section 24 of the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011 not to 
incorporate any consensus standards that are not available to the 
public, for free, on an internet Web site. PHMSA has sought a solution 
to this issue and as a result, all incorporated by reference standards 
in the pipeline safety regulations would be available for viewing to 
the public for free.
Additional Quality Control Standards for ILI Tools, Assessments, and 
Data Review
    In the ANPRM, PHMSA asked if additional quality control standards 
are needed for conducting ILIs using smart pigs, the qualification of 
persons interpreting ILI data, the review of ILI results, and the 
quality and accuracy of ILI tool performance.
Comments
    API-AOPL, LMOGA, TxOGA, and TransCanada Keystone commented that 
PHMSA should adopt API 1163 and American Society of Nondestructive 
Testing ILI PQ. These commenters stated that a certification program 
for analyzing ILI data would not add value to pipeline operators' IM 
programs, as operator experience has shown that these types of programs 
do not adequately reflect the highly technical nature of, and the 
intimate knowledge and experience of personnel practicing, IM programs. 
According to the commenters, there is no evidence that the current 
requirements and industry standards are leaving the public or 
environment at risk.
    NAPSR indicated that if there is data to show this is an issue, 
PHMSA should adopt a standard. Additionally, a state could impose a 
more stringent standard based on prior experience. Both the NSB and 
MAWUC supported adoption of standards for ILI use.
Response
    As noted in the response to the previous question, PHMSA is 
proposing to require operators to consider tool tolerance and other 
uncertainties in evaluating ILI results in complying with the IM 
requirements of Sec.  195.452 and the proposed assessment requirement 
in Sec.  195.416. PHMSA believes that this requirement and the proposed 
changes to the repair criteria will ensure the prompt detection and 
remediation of anomalous conditions (e.g., metal loss, dents, 
corrosion, cracks, gouges, grooves) that could adversely affect the 
safe operation of a pipeline. PHMSA is proposing by a separate 
rulemaking via incorporation by reference available industry consensus 
standards for performing assessments of pipelines using ILI tools, 
internal corrosion direct assessment, and stress corrosion cracking 
direct assessment.

F. Stress Corrosion Cracking

    In the October 2010 ANPRM, PHMSA asked for public comment on 
whether to adopt additional safety standards for stress corrosion 
cracking (SCC). SCC is cracking induced from the combined influence of 
tensile stress and a corrosive medium. Sections 195.553 and 195.588 and 
Appendix C of the Hazardous Liquid Pipeline Safety Standards contain 
provisions for the direct assessment of SCC, but do not include 
comprehensive requirements for preventing, detecting, and remediating 
that condition.

[[Page 61633]]

    Specifically, PHMSA asked in the ANPRM whether:
     Any existing industry standards for preventing, detecting, 
and remediating SCC should be incorporated by reference;
     Any data or statistics are available on the effectiveness 
of these industry standards;
     Any data or statistics are available on the effectiveness 
of SCC detection tools and methodologies;
     Any tools or methods are available for detecting SCC 
associated with longitudinal pipe seams;
     An SCC threat analysis should be conducted for all 
pipeline segments;
     Any particular integrity assessment methods should be used 
when SCC is a credible threat; and
     Operators should be required to perform a periodic 
analysis of the effectiveness of their corrosion management programs.
Adoption of NACE Standard for Stress Corrosion Cracking Direct 
Assessment Methodology or Other Industry Standards
    In the ANPRM, PHMSA asked for comment on whether the agency should 
incorporate any consensus industry standards for assessing SCC, 
including the NACE International (NACE) SP0204-2008 (formerly RP0204), 
Stress Corrosion Cracking (SCC) Direct Assessment Methodology. https://www.nace.org/uploadedFiles/Committees/SP020408.pdf (last accessed 
December 12, 2013) (stating that SP0204-2008 ``provides guidance for 
managing SCC by selecting potential pipeline segments, selecting dig 
sites within those segments, inspecting the pipe and collecting and 
analyzing data during the dig, establishing a mitigation program, 
defining the reevaluation interval, and evaluating the effectiveness of 
the SCC [direct assessment] process.'').
Comments
    API-AOPL, TransCanada Keystone, TxOGA, and LMOGA stated that NACE 
SP0204-2008 provides an effective framework for the application of 
direct assessment, but does not sufficiently address other assessment 
methods, including ILI and hydrostatic testing. These commenters were 
also not aware of any industry statistics that directly correlate the 
application of that standard to the SCC detection or failure rate. 
These commenters stated the most appropriate standard for SCC 
assessment of hazardous liquid pipelines is the soon-to-be-released 
version of API Standard 1160, Managing System Integrity for Hazardous 
Liquid Pipelines.
    Another trade association, TPA, stated that ``because [the NACE 
Standard] was just finished in 2008, PHMSA should wait at least 2-3 
years more before attempting to assess the desirability of 
incorporating that standard into the regulations.''
    One regulatory association, MAWUC, commented that PHMSA should 
adopt standards that address direct assessment, prevention, and 
remediation of SCC. The municipality/government entity, NSB, offered a 
similar comment.
Response
    The commenters did not indicate that NACE SP0204-2008 would address 
the full lifecycle of SCC safety issues. Moreover, none of the 
commenters identified any other industry standards that would be 
appropriate for adoption at this time.
    PHMSA recognizes that SCC is an important safety concern, but does 
not believe that further action can be taken based on the information 
available in this proceeding. PHMSA is establishing a team of experts 
to study this issue and will be holding a public forum on the 
development of SCC standards. Once that process is complete, PHMSA will 
consider whether to establish new safety standards for SCC. With 
respect to NACE SP0204-2008 PHMSA is proposing this standard by a 
separate rulemaking via incorporation by reference.
Identification of Standards and Practices for Prevention, Detection, 
Assessment and Remediation of SCC
    PHMSA asked the public to identify any other standards and 
practices for the prevention, detection, assessment, and remediation of 
SCC.
Comments
    API-AOPL, LMOGA, and TxOGA indicated that there are several good 
standards that address SCC, including API 1160, ASME STP-PT-011, 
Integrity Management of Stress Corrosion Cracking in Gas Pipeline High 
Consequence Areas, and the Canadian Energy Pipeline Association (CEPA) 
Stress Corrosion Cracking Recommended Practices (CEPA SCC RP), but 
acknowledged that all of these standards have weaknesses.
    The trade association, CEPA, also stated that the 2008 ASME STP-PT-
011 should be considered. While written for gas pipelines, CEPA stated 
that this standard could be adapted to hazardous liquids.
Response
    PHMSA appreciates the information provided by the commenters. PHMSA 
will be studying the SCC issue and will consider incorporating by 
reference suggested standards in future rulemakings.
Implementation of Canadian Energy Pipeline Association RP on SCC
    CEPA is an organization that represents Canada's transmission 
pipeline companies. In 1997, CEPA developed its SCC Recommended 
Practice (RP) in response to a public inquiry by National Energy Board 
of Canada. In 2007, CEPA released an updated version of its SCC RP, 
https://www.cepa.com/wp-content/uploads/2011/06/Stress-Corrosion-Cracking-Recommended-Practices-2007.pdf. In the ANPRM, PHSMA asked for 
comment on the experience of operators in implementing CEPA's SCC RP.
Comments
    API-AOPL, LMOGA, TxOGA, and TransCanada Keystone commented that the 
CEPA SCC RP provides the most thorough overview of the various 
assessment techniques, but is limited to near neutral SCC in terms of 
causal considerations. These commenters also stated that there are no 
industry statistics on the application of the CEPA RP SCC. CEPA and 
API-AOPL both indicated that companies continue to use the CEPA SCC RP 
as a guideline, but that there are no statistics on its use.
Response
    PHMSA appreciates the comments provided on the use of the CEPA SCC 
RP and will consider that standard in its study of comprehensive safety 
requirements for SCC and in future rulemakings.
 Effectiveness of SCC Detection Tools and Methods
    PHMSA requested comment as to the effectiveness of current SCC 
detection tools and methods.
Comments
    API-AOPL, supported by LMOGA, TxOGA, and TransCanada Keystone, 
stated that there are no industry statistics that directly correlate 
the application of the CEPA RP to the SCC detection or failure rate, 
but that the National Energy Board of Canada has noted the 
effectiveness of the CEPA RP for managing SCC. API-AOPL also stated the 
planned revisions of API 1160 and 1163 will address the current gaps 
regarding SCC in the standards and recommended practices relevant to 
liquid pipelines. One citizens' group,

[[Page 61634]]

TWS, mentioned that gathering lines do not require corrosion prevention 
and that this should be required.
Response
    PHMSA appreciates the comments provided on the effectiveness of SCC 
detection tools and methods and will be considering that information in 
evaluating comprehensive safety requirements for SCC and consider 
incorporating in future rulemakings.

IV. 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 part 195, including gathering lines that cross 
waterways used for commercial navigation as well as certain onshore 
gathering lines (i.e., those that are located in a non-rural area, that 
meet the definition of a regulated onshore gathering line, or that are 
located in an inlet of the Gulf of Mexico). PHMSA has determined that 
additional information about unregulated gathering lines is needed to 
fulfill its statutory obligations. Accordingly, the NPRM extend the 
reporting requirements in subpart B of part 195 to all gathering lines 
(whether regulated, unregulated, onshore, or offshore) by adding a new 
paragraph (a)(5) to Sec.  195.1.

Sec.  195.2 Definitions

    Section 195.2 provides definitions for various terms used 
throughout part 195. On August 10, 2007, (72 FR 45002; Docket number 
PHMSA-2007-28136) PHMSA published a policy statement and request for 
comment on the transportation of ethanol, ethanol blends, and other 
biofuels by pipeline. PHMSA noted in the policy statement that the 
demand for biofuels was projected to increase in the future as a result 
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 now proposing to modify its definition of hazardous liquid 
in Sec.  195.2. Such a change would make clear that the transportation 
of biofuel by pipeline is subject to the requirements of 49 CFR part 
195.
    PHMSA is also proposing to add a new definition of ``Significant 
Stress Corrosion Cracking.'' This new definition will provide criteria 
for determining when a probable crack defect in a pipeline segment must 
be excavated and repaired.

Sec.  195.11 What is a regulated rural gathering line and what 
requirements apply?

    Section 195.11 defines and establishes the requirements that are 
applicable to regulated rural gathering lines. PHMSA has determined 
that these lines should be subject to the new requirements in the NPRM 
for the performance of periodic pipeline assessments and pipeline 
remediation and for establishing leak detection systems. Consequently, 
the NPRM would amend Sec.  195.11 by adding paragraphs (b)(12) and (13) 
to ensure that these requirements are applicable to regulated rural 
gathering lines.

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

    Section 195.13 will be added which subjects gravity lines to the 
same reporting requirements in subpart B of part 195 as other hazardous 
liquid pipelines. PHMSA has determined that additional information 
about gravity lines is needed to fulfill its statutory obligations.

Sec.  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, the NPRM would repeal 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 would be re-organized without altering the 
existing substantive requirements.

Sec.  195.134 Leak Detection

    Section 195.134 contains the design requirements for computational 
pipeline monitoring leak detection systems. The NPRM would restructure 
the existing requirements into paragraphs (a) and (b) and add a new 
provision in paragraph (c) to ensure that all newly constructed 
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.

Sec.  195.401 General Requirements

    Section 195.401 prescribes general requirements for the operation 
and maintenance of hazardous liquid pipelines. PHMSA is proposing to 
modify the pipeline repair requirements in Sec.  195.401(b). Paragraph 
(b)(1) will be modified to reference the new timeframes in Sec.  
195.422 for performing non-IM repairs. The requirements in paragraph 
(b)(2) for IM repairs will be retained without change. A new paragraph 
(b)(3) will be 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, including those covered by the 
timeframes specified in Sec. Sec.  195.422(d) and (e) and 195.452(h).

Sec.  195.414 Inspections of Pipelines in Areas Affected by Extreme 
Weather, a Natural Disaster, and Other Similar Events

    Extreme weather, natural disasters and other similar events can 
affect the safe operation of a pipeline. Accordingly, the NPRM would 
establish a new regulation in Sec.  195.414 that would require 
operators to perform inspections after these events and to take 
appropriate remedial actions.

Sec.  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 that is needed to promptly detect and remediate conditions 
that could affect the safe operation of pipelines in all areas. 
Accordingly, the NPRM would establish a new regulation in Sec.  195.416 
that requires operators to perform an assessment of pipelines that are 
not already subject to the IM requirements at least once every 10 
years. The regulation would require that these assessments be performed 
with an ILI tool, unless an operator demonstrates and provides 90-days 
prior notice that a pipeline is not capable of accommodating such a 
device and that an alternative method will provide a substantially 
equivalent understanding of its condition.

[[Page 61635]]

    The regulation would also require 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 new requirements in Sec.  195.422 of the NPRM; and 
that all relevant information about the pipeline be considering in 
complying with the requirements of Sec.  195.416.

Sec.  195.422 Pipeline Remediation

    Section 195.422 contains the requirements for performing pipeline 
repairs. PHMSA has determined that new criteria should be established 
for remediating conditions that affect the safe operation of a 
pipeline. The NPRM would add a new paragraph (a) specifying that the 
provisions in the regulation are applicable to pipelines that are not 
subject to the IM requirements in Sec.  195.452 (e.g., not in HCAs). 
Paragraphs (b) and (c) would contain the existing requirements in the 
regulation, including the general duty clause for ensuring public 
safety and the provision noting the applicability of the design and 
construction requirements to piping and equipment used in performing 
pipeline repairs. Paragraph (d) would establish a new remediation 
schedule based on the analogous provisions in the IM requirements for 
performing immediate and 18-month repairs, and paragraph (e) would 
contain a residual provision for remediating all other conditions.

Sec.  195.444 Leak Detection

    Section 195.444 contains the operation and maintenance requirements 
for Computational Pipeline Monitoring leak detection systems. PHMSA is 
proposing that all pipelines should have leak detection systems. 
Therefore, the NPRM would reorganize the existing requirements of the 
regulation into paragraphs (a) and (c), and add a new general provision 
in paragraph (b) that would require operators to have leak detection 
systems on all 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 NPRM would clarify the applicability of the deadlines in paragraph 
(b) for the development of a written program for new pipelines, 
regulated rural gathering lines, and low-stress pipelines in rural 
areas. Paragraph (c)(1)(i)(A) would also be amended to ensure that 
operators consider uncertainty in tool tolerance in reviewing the 
results of ILI assessments. Paragraph (d) would be amended to eliminate 
obsolete deadlines for performing baseline assessments and to clarify 
the requirements for newly-identified HCAs. Paragraph (e)(1)(vii) is 
amended to include local environmental factors that might affect 
pipeline integrity. Paragraph (g) would be amended to expand upon the 
factors and criteria that operators must consider in performing the 
information analysis that is required in periodically evaluating the 
integrity of covered pipeline segments. Paragraph (h)(1) would also be 
amended by modifying the criteria, and establishing a new, consolidated 
timeframe, for performing immediate and 270-day pipeline repairs based 
on the information obtained as a result of ILI assessments or through 
an information analysis of a covered segment.
    PHMSA is also proposing to amend the existing ``discovery of 
condition'' language in the pipeline safety regulations. The revised 
Sec.  195.452(h)(2) will require, in cases where a determination about 
pipeline threats has not been obtained within 180 days following the 
date of inspection, that pipeline operators must notify PHMSA and 
provide an expected date when adequate information will become 
available. Paragraphs 195.452(h)(4)(i)(E) and (F) are also added to 
address issues of significant stress corrosion cracking and selective 
seam corrosion.
    PHMSA proposes further changes to Sec.  195.452. These changes 
include paragraph (j) which would be 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) would also be added to require that all pipelines in 
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 permit that accommodation or the existence of an emergency renders 
such an accommodation impracticable. Paragraph (n) would also require 
that pipelines in newly-identified HCAs after the 20-year period be 
made capable of accommodating ILIs within five years of the date of 
identification or before the performance of the baseline assessment, 
whichever is sooner. Finally, an explicit reference to seismicity will 
be 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).

V. Regulatory Notices

A. Executive Order 12866, Executive Order 13563, and DOT Regulatory 
Policies and Procedures

    Executive Orders 12866 and 13563 require agencies to regulate in 
the ``most cost-effective manner,'' to make a ``reasoned determination 
that the benefits of the intended regulation justify its costs,'' and 
to develop regulations that ``impose the least burden on society.'' 
This action has been determined to be significant under Executive Order 
12866 and the Department of Transportation's Regulatory Policies and 
Procedures. It has been reviewed by the Office of Management and Budget 
in accordance with Executive Order 13563 (Improving Regulation and 
Regulatory Review) and Executive Order 12866 (Regulatory Planning and 
Review) and is consistent with the requirements in both orders.
    In the regulatory analysis, we discuss the alternatives to the 
proposed requirements and, where possible, provide estimates of the 
benefits and costs for specific regulatory requirements in the eight 
areas. The regulatory analysis provides PHMSA's best estimate of the 
impact of the separate requirements. The chart below summarizes the 
cost/benefit analysis:

                    Annualized Costs and Benefits by Requirement Area Discounted at 7 Percent
----------------------------------------------------------------------------------------------------------------
           Requirement area                     Costs                   Benefits               Net benefits
----------------------------------------------------------------------------------------------------------------
1. Extend certain reporting            $900...................  Benefits not             Expected to be
 requirements to all hazardous liquid                            quantified, but          positive.
 (HL) gravity lines.                                             expected to justify
                                                                 costs.

[[Page 61636]]

 
2. Extend certain reporting            23,300.................  Benefits not quantified  Expected to be
 requirements to all hazardous liquid                            but expected to          positive.
 (HL) gathering lines.                                           justify the costs.
3. Require inspections of pipelines    1.5 million............  3.5 to 10.4 million....  2.0 to 8.9 million
 in areas affected by extreme
 weather, natural disasters, and
 other similar events, as well as
 appropriate remedial action if a
 condition that could adversely
 affect the safe operation of a
 pipeline is discovered.
4. Require periodic assessments of     16.7 million...........  17.7 million...........  1 million
 pipelines that are not already                                 Range 9.4-26.0 million.  Range (-)7.3-9.3
 covered under the IM program                                                             million
 requirements using an in-line                                                           Expected to be positive
 inspection tool (or demonstrate to                                                       even at the low end of
 the satisfaction of PHMSA that the                                                       the benefit range if
 pipeline is not capable of using                                                         unquantified benefits
 this tool).                                                                              are included.
5. Require use of leak detection       Not quantified but       Not quantified, but      Not quanitified, but
 systems (LDS) on new HL pipelines      expected to be minimal.  expected to justify      positive qualitative
 located in non-HCAs to mitigate the                             the minimal costs.       benefits.
 effects of failures that occur
 outside of HCAs.
6. Modify the IM repair criteria,      Not quantified, but      Not quantified, but      Not quantified, but
 both by expanding the list of          expected to be minimal.  expected to justify      expected to be
 conditions that require immediate                               the minimal costs.       minimal.
 remediation, consolidating the
 timeframes for remediating all other
 conditions, and making explicit
 deadlines for repairs on non-IM
 pipeline.
7. Increase the use of inline          1.0 million............  12.2 million...........  11.2 million
 inspection (ILI) tools by requiring
 that any pipeline that could affect
 an HCA be capable of accommodating
 these devices within 20 years,
 unless its basic construction will
 not permit that accommodation.
8. Clarify and resolve                 3.2 million............  10.0 million...........  6.8 million.
 inconsistencies regarding deadlines,
 and information analyses for IM
 Plans t.
----------------------------------------------------------------------------------------------------------------

    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 are in excess of the cost. PHMSA seeks comment on 
the Preliminary Regulatory Evaluation, its approach, and the accuracy 
of its estimates of costs and benefits. A copy of the Preliminary 
Regulatory evaluation has been placed in the docket.

B. Executive Order 13132: Federalism

    This NPRM has been analyzed in accordance with the principles and 
criteria contained in Executive Order 13132 (``Federalism''). This NPRM 
does not propose 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 propose 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. Nevertheless, PHMSA has and will 
continue to consult extensively with state regulators including NAPSR 
to ensure that any state concerns are taken into account.

C. 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

[[Page 61637]]

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 potential economic 
impact on small entities. The screening analysis is available in the 
docket for the rulemaking. PHMSA estimates that the proposed rule would 
impact fewer than 100 small hazardous liquid pipeline operators, and 
that the majority of these operators would experience annual compliance 
costs that represent less than 1% of annual revenues. Less than 20 
small operators would incur annual compliance costs that represent 
greater than 1% of annual revenues; less than 10 would incur annual 
compliance costs of greater than 3% of annual revenues; and none would 
incur compliance costs of more than 20% of annual revenues. PHMSA 
determined that these impacts results do not represent a significant 
impact for a substantial number of small hazardous liquid pipeline 
operators. Therefore, I certify that this action, if promulgated, will 
not have a significant economic impact on a substantial number of small 
entities.

D. National Environmental Policy Act

    PHMSA analyzed this NPRM 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 preliminarily determined that this action 
will not significantly affect the quality of the human environment. A 
preliminary environmental assessment of this rulemaking is available in 
the docket and PHMSA invites comment on environmental impacts of this 
rule, if any.

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

    This NPRM has been analyzed in accordance with the principles and 
criteria contained in Executive Order 13175 (``Consultation and 
Coordination with Indian Tribal Governments''). Because this NPRM 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.

F. Paperwork Reduction Act

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 that the proposals in this rulemaking will 
add a new information collection and impact several approved 
information collections titled:
    ``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 and;
    ``Pipeline Safety: New Reporting Requirements for Hazardous Liquid 
Pipeline Operators: Hazardous Liquid Annual Report'' identified under 
OMB Control Number 2137-0614.
    Based on the proposals in this rulemaking, PHMSA will submit an 
information collection revision request to OMB for approval based on 
the requirements in this NPRM. The information collection is contained 
in the pipeline safety regulations, 49 CFR parts 190 through 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: April 30, 2014.
    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. Additional information is also 
obtained concerning the characteristics of an operator's pipeline 
system. As a result of this NPRM, 5 gravity line operators and 23 
gathering line operators would be required to submit accident reports 
to PHMSA on occasion. These 28 additional operators will also be 
required to keep mandated records. This information collection is being 
revised to account for the additional burden that will be incurred by 
these newly regulated entities. Operators currently submitting annual 
reports will not be otherwise impacted by this NPRM.
    Affected Public: Owners and operators of Hazardous Liquid 
Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 881.
    Total Annual Burden Hours: 55,455.
    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: May 31, 2014.
    Abstract: 49 U.S.C. 60102 requires each operator of a pipeline 
facility (except master meter operators) to submit to 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 hazards to life, property or the 
environment. As a result of this NPRM, approximately 5 gravity line 
operators and 23 gathering line operators will be required to adhere to 
the Safety-Related Condition reporting requirements. 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: 178.
    Total Annual Burden Hours: 1,020.
    Frequency of Collection: On occasion.
    3. Title: Integrity Management in High Consequence Areas for 
Operators of Hazardous Liquid Pipelines.
    OMB Control Number: 2137-0605.
    Current Expiration Date: November 30, 2016.
    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

[[Page 61638]]

remedial preventive and mitigative actions. As a result of this NPRM, 
operators not currently under IM plans will be required to adhere to 
the repair criteria currently required for operators who are under IM 
plans. In conjunction with this requirement, operators who are not able 
to make the necessary repairs within 180 days of the infraction will be 
required to notify PHMSA in writing. PHMSA estimates that only 1% of 
repair reports will require more than 180 days. Accordingly, PHMSA 
approximates that 75 reports per year will fall within this category.
    Affected Public: Owners and operators of Hazardous Liquid 
Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 278.
    Total Annual Burden Hours: 325,508.
    Frequency of Collection: Annually.
    4. Title: Pipeline Safety: New Reporting Requirements for Hazardous 
Liquid Pipeline Operators: Hazardous Liquid Annual Report.
    OMB Control Number: 2137-0614.
    Current Expiration Date: April 30, 2014.
    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 compile a national pipeline inventory, identify safety problems, 
and target inspections. As a result of this NPRM, approximately 5 
gravity line operators and 23 gathering line operators will be required 
to submit annual reports to PHMSA. This information collection is being 
revised to account for the additional burden that will be incurred. 
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: 8,567.
    Frequency of Collection: Annually.
    5. Title: Pipeline Safety: Notification Requirements for Hazardous 
Liquid Operators.
    OMB Control Number: New OMB Control No.
    Current Expiration Date: TBD.
    Abstract: Owners and operators of non-High Consequence Area 
hazardous liquid pipelines will be required to provide PHMSA with 
notifications when unable to assess their pipeline via an in-line 
inspection.
    Affected Public: Owners and operators of Hazardous Liquid 
Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 10.
    Total Annual Burden Hours: 10.
    Frequency of Collection: On occasion.

    Requests for copies of these information collections should be 
directed to Angela Dow or Cameron Satterthwaite, Office of Pipeline 
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration 
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE., Washington, DC 20590-
0001, Telephone (202) 366-4595.

G. 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.

H. 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 proposes to amend 49 CFR 
part 195 as follows:

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
1. The authority citation for part 195 is revised to read as follows:

    Authority: 49 U.S.C. 5103, 60101, 60102, 60104, 60108, 60109, 
60116, 60118, 60131, 60131, 60137, and 49 CFR 1.97.
0
2. In Sec.  195.1, paragraph (a)(5) is added, paragraph (b)(2) is 
removed, and paragraphs (b)(3) through (10) are re-designated as (b)(2) 
through (9).
    The addition reads 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.
* * * * *
0
3. In section 195.2, the definition for ``Hazardous liquid'' is revised 
and a definition of ``Significant stress corrosion cracking'' is added 
in alphabetical order to read as follows:


Sec.  195.2  Definitions.

* * * * *
    Hazardous liquid means petroleum, petroleum products, anhydrous 
ammonia or non-petroleum fuel, including biofuel that is flammable, 
toxic, or corrosive or would be harmful to the environment if released 
in significant quantities.
* * * * *
    Significant stress corrosion cracking means a stress corrosion 
cracking (SCC) cluster in which the deepest crack, in a series of 
interacting cracks, is greater than 10% of the wall thickness and the 
total interacting length of the cracks is equal to or greater than 75% 
of the critical length of a 50% through-wall flaw that would fail at a 
stress level of 110% of SMYS.
* * * * *
0
4. In section 195.11, add paragraphs (b)(12) and (13) to read as 
follows:


Sec.  195.11  What is a regulated rural gathering line and what 
requirements apply?

* * * * *
    (b) * * *
    (12) Perform pipeline assessments and remediation as required under 
Sec. Sec.  195.416 and 195.422.
    (13) Establish a leak detection system in compliance with 
Sec. Sec.  195.134 and 195.444.
* * * * *
0
5. Section 195.13 is added to subpart A to read as follows:


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

    (a) Scope. This section applies to pipelines transporting hazardous 
liquids by gravity as of [effective date of the final rule].
    (b) Annual, accident and safety related reporting. Comply with the 
reporting requirements in subpart B of this part by [date 6 months 
after effective date of the final rule].
0
6. Section 195.120 is revised 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

[[Page 61639]]

pipe, valve, fitting or other line component is replaced must be 
designed and constructed to accommodate the passage of instrumented 
internal inspection devices.
    (b) Exceptions. This section does not apply to:
    (1) Manifolds;
    (2) Station piping such as at pump stations, meter stations, or 
pressure reducing stations;
    (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 main 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) 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 the petition is denied, 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
7. Section 195.134 is revised to read as follow:


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. Each pipeline must have a system for detecting leaks 
that complies with the requirements in Sec.  195.444.
    (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.
0
8. In Sec.  195.401, the introductory text of paragraph (b) and 
paragraph (b)(1) are revised and paragraph (b)(3) is added to read as 
follows.


Sec.  195.401  General requirements.

* * * * *
    (b) An operator must make repairs on its pipeline system according 
to the following requirements:
    (1) Non integrity management repairs. Whenever an operator 
discovers any condition that could adversely affect the safe operation 
of a pipeline not covered under Sec.  195.452, it must correct the 
condition as prescribed in Sec.  195.422. 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.
* * * * *
    (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
9. Section 195.414 is added to read as follows:


Sec.  195.414  Inspections of pipelines in areas affected by extreme 
weather, a natural disaster, and other similar events.

    (a) General. Following an extreme weather event such as a hurricane 
or flood, an earthquake, a natural disaster, or other similar event, an 
operator must inspect all potentially affected pipeline facilities to 
ensure that no conditions exist 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 inspection required under 
paragraph (a) of this section.
    (c) Time period. The inspection required under paragraph (a) of 
this section must occur within 72 hours after the cessation of the 
event, or as soon as 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.
    (d) Remedial action. An operator must take 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
10. Section 195.416 is added to read as follows:


Sec.  195.416  Pipeline assessments.

    (a) Scope. This section applies to pipelines that are not subject 
to the integrity management requirements in Sec.  195.452.
    (b) General. An operator must perform an assessment of a pipeline 
at least once every 10 years, or as otherwise necessary to ensure 
public safety.
    (c) Method. The assessment required under paragraph (b) of this 
section must be performed with an in-line inspection tool or tools 
capable of detecting corrosion and deformation anomalies, including 
dents, cracks, gouges, and grooves, unless an operator:
    (i) Demonstrates that the pipeline is not capable of accommodating 
an inline inspection tool; and that the use of an alternative 
assessment method will provide a substantially equivalent understanding 
of the condition of the pipeline; and
    (ii) Notifies the Office of Pipeline Safety (OPS) 90 days before 
conducting the assessment by:
    (A) Sending the notification, along with the information required 
to demonstrate compliance with paragraph (c)(i) of this section, to the 
Information Resources Manager, Office of Pipeline Safety, Pipeline and 
Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., 
Washington, DC 20590; or
    (B) Sending the notification, along with the information required 
to demonstrate compliance with paragraph (c)(i) of this section, to the 
Information Resources Manager by facsimile to (202) 366-7128.
    (d) 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. Uncertainties in 
any reported results (including tool tolerance) must be considered as 
part of that analysis.
    (e) Discovery of condition. For purposes of Sec.  195.422, 
discovery of a

[[Page 61640]]

condition occurs when an operator has adequate information to determine 
that a condition exists. An operator must promptly, but no later than 
180 days after an assessment, obtain sufficient information about a 
condition and make the determination required under paragraph (d) of 
this section, unless 180-days is impracticable as determined by PHMSA.
    (f) Remediation. An operator must comply with the requirements in 
Sec.  195.422 if a condition that could adversely affect the safe 
operation of a pipeline is discovered in complying with paragraphs (d) 
and (e) of this section.
    (g) Consideration of information. An operator must consider all 
relevant information about a pipeline in complying with the 
requirements in paragraphs (a) through (f) of this section.
0
11. Section 195.422 is revised to read as follows:


Sec.  195.422  Pipeline remediation.

    (a) Scope. This section applies to pipelines that are not subject 
to the integrity management requirements in Sec.  195.452.
    (b) General. Each operator must, in repairing its pipeline systems, 
ensure that the repairs are made in a safe manner and are made so as to 
prevent damage to persons, property, or the environment.
    (c) Replacement. An operator may not use any pipe, valve, or 
fitting, for replacement in repairing pipeline facilities, unless it is 
designed and constructed as required by this part.
    (d) Remediation schedule. An operator must complete the remediation 
of a condition according to the following schedule:
    (1) Immediate repair conditions. An operator must repair the 
following conditions immediately upon discovery:
    (i) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (ii) A calculation of the remaining strength of the pipe shows a 
burst pressure less than 1.1 times the maximum operating pressure at 
the location of the anomaly. Suitable remaining strength calculation 
methods include, but are not limited to, ASME/ANSI B31G (``Manual for 
Determining the Remaining Strength of Corroded Pipelines'' (1991) or 
AGA Pipeline Research Committee Project PR-3-805 (``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe'' 
(December 1989)) (incorporated by reference, see Sec.  195.3.
    (iii) A dent located anywhere on the pipeline that has any 
indication of metal loss, cracking or a stress riser.
    (iv) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) with a depth greater than 6% of the nominal pipe 
diameter.
    (v) An anomaly that in the judgment of the person designated by the 
operator to evaluate the assessment results requires immediate action.
    (vi) Any indication of significant stress corrosion cracking (SCC).
    (vii) Any indication of selective seam weld corrosion (SSWC).
    (2) Until the remediation of a condition specified in paragraph 
(d)(1) of this section is complete, an operator must:
    (i) Reduce the operating pressure of the affected pipeline using 
the formula specified in paragraph 195.422(d)(3)(iv) or;
    (ii) Shutdown the affected pipeline.
    (3) 18-month repair conditions. An operator must repair the 
following conditions within 18 months of discovery:
    (i) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or a longitudinal seam weld.
    (ii) A dent located on the top of the pipeline (above 4 and 8 
o'clock position) with a depth greater than 2% of the pipeline's 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12).
    (iii) A dent located on the bottom of the pipeline with a depth 
greater than 6% of the pipeline's diameter.
    (iv) A calculation of the remaining strength of the pipe at the 
anomaly shows a safe operating pressure that is less than the MOP at 
that location. Provided the safe operating pressure includes the 
internal design safety factors in Sec.  195.106 in calculating the pipe 
anomaly safe operating pressure, suitable remaining strength 
calculation methods include, but are not limited to, ASME/ANSI B31G 
(``Manual for Determining the Remaining Strength of Corroded 
Pipelines'' (1991)) or AGA Pipeline Research Committee Project PR-3-805 
(``A Modified Criterion for Evaluating the Remaining Strength of 
Corroded Pipe'' (December 1989)) (incorporated by reference, see Sec.  
195.3).
    (v) An area of general corrosion with a predicted metal loss 
greater than 50% of nominal wall.
    (vi) Predicted metal loss greater than 50% of nominal wall that is 
located at a crossing of another pipeline, or is in an area with 
widespread circumferential corrosion, or is in an area that could 
affect a girth weld.
    (vii) A potential crack indication that when excavated is 
determined to be a crack.
    (viii) Corrosion of or along a seam weld.
    (ix) A gouge or groove greater than 12.5% of nominal wall.
    (e) Other conditions. Unless another timeframe is specified in 
paragraph (d) of this section, an operator must take appropriate 
remedial action to correct any condition that could adversely affect 
the safe operation of a pipeline system within a reasonable time.
0
12. Section 195.444 is revised to read as follows:


Sec.  195.444  Leak detection.

    (a) Scope. This section applies to each hazardous liquid pipeline 
transporting liquid in single phase (without gas in the liquid).
    (b) General. A pipeline must have a system for detecting leaks. An 
operator must evaluate and modify, as necessary, the capability of its 
leak detection system to protect the public, property, and the 
environment. An operator's evaluation must, at least, 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
13. In Sec.  195.452:
0
a. Revise paragraphs (a), (b)(1), introductory text of paragraph 
(c)(1)(i), (c)(1)(i)(A), (d), (e)(1)(vii), (g), introductory text of 
(h)(1), (h)(2), and (h)(4);
0
b. Revise paragraph (i)(2)(viii) by removing the period at the end of 
the last sentence and adding in its place a ``;'' and add paragraph 
(i)(2)(ix);
0
c. Revise paragraphs (j)(1) and (2);
0
d. Add paragraph (n).
    The revisions and additions read as follows:


Sec.  195.452  Pipeline integrity management in high consequence areas.

    (a) Which pipelines are covered by this section? This section 
applies to each hazardous liquid pipeline and carbon dioxide pipeline 
that could affect a high consequence area, including any pipeline 
located in a high consequence area, unless the operator demonstrates 
that a worst case discharge from the pipeline could not affect the 
area. (Appendix C of this part provides

[[Page 61641]]

guidance on determining if a pipeline could affect a high consequence 
area.) Covered pipelines are categorized as follows:
    (1) Category 1 includes pipelines existing on May 29, 2001, that 
were owned or operated by an operator who owned or operated a total of 
500 or more miles of pipeline subject to this part.
    (2) Category 2 includes pipelines existing on May 29, 2001, that 
were owned or operated by an operator who owned or operated less than 
500 miles of pipeline subject to this part.
    (3) Category 3 includes pipelines constructed or converted after 
May 29, 2001, 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 not 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.
------------------------------------------------------------------------

* * * * *
    (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 unless it is impracticable, then use methods (B), (C) 
or (D) of this paragraph. The methods an operator selects to assess low 
frequency electric resistance welded pipe, or lap welded pipe, or 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 and of detecting corrosion and deformation 
anomalies.
    (A) Internal inspection tool or tools capable of detecting 
corrosion, and deformation anomalies including dents, cracks (pipe body 
and weld seams), gouges and grooves. 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 the pipeline begins operation.
    (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 one 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 five 
years from the date the area is identified.
* * * * *
    (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. This analysis must:
    (1) Integrate information and attributes about the pipeline which 
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);
    (iv) Endpoints of segments that could affect high consequence areas 
(HCAs);
    (v) Hydrostatic test pressure including any test failures--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 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. 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.
* * * * *
    (2) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information to determine that a condition exists. 
An operator must promptly, but no later than 180 days after an 
assessment, obtain sufficient information about a condition and make 
the determination required, unless the operator can demonstrate that 
that 180-day is impracticable. If 180-days is impracticable to make a

[[Page 61642]]

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.
* * * * *
    (4) Special requirements for scheduling remediation--(i) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must provide for immediate repair conditions. To maintain safety, an 
operator must temporarily reduce the operating pressure or shut down 
the pipeline until the operator completes the repair of these 
conditions. An operator must calculate the temporary reduction in 
operating pressure using the formulas in paragraph (h)(4)(i)(B) of this 
section, if applicable, or when the formulas in paragraph (h)(4)(i)(B) 
of this section are not applicable by using a pressure reduction 
determination in accordance with Sec.  195.106 and the appropriate 
remaining pipe wall thickness, or if all of these are unknown a minimum 
20 percent or greater operating pressure reduction must be implemented 
until the anomaly is repaired. If the formula is not applicable to the 
type of anomaly or would produce a higher operating pressure, an 
operator must use an alternative acceptable method to calculate a 
reduced operating pressure. An operator must treat the following 
conditions as immediate repair conditions:
    (A) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (B) A calculation of the remaining strength of the pipe shows a 
predicted burst pressure less than 1.1 times the maximum operating 
pressure at the location of the anomaly. Suitable remaining strength 
calculation methods include, but are not limited to, ASME/ANSI B31G 
(``Manual for Determining the Remaining Strength of Corroded 
Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3-805 
(``A Modified Criterion for Evaluating the Remaining Strength of 
Corroded Pipe'' (December 1989)) (incorporated by reference, see Sec.  
195.3).
    (C) A dent located anywhere on the pipeline that has any indication 
of metal loss, cracking or a stress riser.
    (D) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) with a depth greater than 6% of the nominal pipe 
diameter.
    (E) Any indication of significant stress corrosion cracking (SCC).
    (F) Any indication of selective seam weld corrosion (SSWC)
    (G) An anomaly that in the judgment of the person designated by the 
operator to evaluate the assessment results requires immediate action.
    (ii) 270-day conditions. Except for conditions listed in paragraph 
(h)(4)(i) of this section, an operator must schedule evaluation and 
remediation of the following within 270 days of discovery of the 
condition:
    (A) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or a longitudinal seam weld.
    (B) A dent located on the top of the pipeline (above 4 and 8 
o'clock position) with a depth greater than 2% of the pipeline's 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12).
    (C) A dent located on the bottom of the pipeline with a depth 
greater than 6% of the pipeline's diameter.
    (D) A calculation of the remaining strength of the pipe at the 
anomaly shows a safe operating pressure that is less than MOP at that 
location. Provided the safe operating pressure includes the internal 
design safety factors in Sec.  195.106 in calculating the pipe anomaly 
safe operating pressure, suitable remaining strength calculation 
methods include, but are not limited to, ASME/ANSI B31G (``Manual for 
Determining the Remaining Strength of Corroded Pipelines'' (1991)) or 
AGA Pipeline Research Committee Project PR-3-805 (``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe'' 
(December 1989)) (incorporated by reference, see Sec.  195.3).
    (E) An area of general corrosion with a predicted metal loss 
greater than 50% of nominal wall.
    (F) Predicted metal loss greater than 50% of nominal wall that is 
located at a crossing of another pipeline, or is in an area with 
widespread circumferential corrosion, or is in an area that could 
affect a girth weld.
    (G) A potential crack indication that when excavated is determined 
to be a crack.
    (H) Corrosion of or along a longitudinal seam weld.
    (I) A gouge or groove greater than 12.5% of nominal wall.
    (iii) Other Conditions. In addition to the conditions listed in 
paragraphs (h)(4)(i) and (ii) of this section, an operator must 
evaluate any condition identified by an integrity assessment or 
information analysis that could impair the integrity of the pipeline, 
and as appropriate, schedule the condition for remediation. Appendix C 
of this part contains guidance concerning other conditions that an 
operator should evaluate.
    (i) * * *
    (2) * * *
    (ix) Seismicity of the area.
* * * * *
    (j) * * * (1) General. After completing the baseline integrity 
assessment, an operator must continue to assess the line pipe at 
specified intervals and periodically evaluate the integrity of each 
pipeline segment that could affect a high consequence area.
    (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 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 new risk factors should be 
considered, 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 under this paragraph no later than [date one year 
after effective date of the final rule].
* * * * *
    (n) Accommodation of 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 [date 20 years from effective date of the final rule].
    (3) Newly-identified areas. If a pipeline could affect a newly-
identified high consequence area (see paragraph (d)(3) of this section) 
after [date 20 years from effective date of the final rule], an 
operator must modify the pipeline to accommodate the passage of an 
instrumented internal inspection device within five 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

[[Page 61643]]

the basic construction (i.e. length, diameter, operating pressure, or 
location) of a pipeline cannot be modified to accommodate the passage 
of an internal inspection device.
    (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. Such a petition must be filed 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 one year after the date 
of the notice of the denial.

    Issued in Washington, DC on October 1, 2015, under authority 
delegated in 49 CFR Part 1.97(a).
Linda Daugherty,
Deputy Associate Administrator for Field Operations.
[FR Doc. 2015-25359 Filed 10-9-15; 8:45 am]
 BILLING CODE 4910-60-P