Integrity Management: Program Modifications and Clarifications-Request for Comments, 74265-74270 [05-24061]

Download as PDF Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules of line pipe, valve, fitting, or other line component in a transmission line to reduce the risk that liquids will collect in the line. At a minimum, unless an operator shows that it is impracticable or unnecessary to do so, an operator must: (1) Configure new pipeline or replacement of line pipe, valve, fitting, or other line component to reduce the risk that liquids will collect in the line; and (2) Equip the new pipeline or replacement pipe with effective liquid removal features. (b) Monitoring. An operator must design and construct each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line to reduce the risk of internal corrosion. At a minimum, unless an operator shows that it is impracticable or unnecessary to do so, an operator must use pipeline design and construction that allows use of corrosion monitoring devices at locations with significant potential for internal corrosion. (c) Change to existing system. An operator must evaluate the impact that new or replaced line pipe, valve, fitting, or other line component may have on internal corrosion risk to the downstream portion of an existing pipeline and use equipment to remove liquids and to monitor corrosion as appropriate. (d) Records. An operator must document the design and construction decisions related to internal corrosion. Documentation must include the reasons, and any engineering analysis, for each decision. Issued in Washington, DC, on December 12, 2005. Stacey L. Gerard, Associate Administrator for Pipeline Safety. [FR Doc. 05–24063 Filed 12–12–05; 1:29 pm] BILLING CODE 4910–60–P DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 192 and 195 [Docket No. PHMSA–04–18938] RIN 2137–AE07 Integrity Management: Program Modifications and Clarifications— Request for Comments Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Notice of proposed rulemaking. AGENCY: VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 SUMMARY: PHMSA proposes revisions to the current Pipeline Safety Regulations for Pipeline Integrity Management in High Consequence Areas. The revisions address a petition from the hazardous liquid pipeline industry. The revisions are to: allow more flexibility in reassessment intervals for hazardous liquid pipelines by adding an eightmonth window to the five-year time frame for operators to complete reassessment; and require both hazardous liquid pipeline and gas transmission pipeline operators to notify PHMSA whenever they reduce pipeline pressure to make a repair and to provide reasons for pressure reduction. Another notification, including reasons for repair delay, would be required when a pressure reduction exceeds 365 days. Also, PHMSA proposes to correct existing provisions for calculating a pressure reduction when making an immediate repair on a hazardous liquid pipeline. The proposed correction would allow operators to use another acceptable method to calculate reduced operating pressure when a specified formula is not applicable or results in a calculated pressure higher than operating pressure. Finally, PHMSA seeks the submittal of engineering analyses and technical data. These submittals are to provide the basis for modifying the required time periods for remediating certain conditions found during a hazardous liquid pipeline integrity assessment. PHMSA will use this data to evaluate the scope and scale of repair issues to develop an accurate basis for determining if any additional flexibility is needed in the repair schedules. DATES: Interested persons may submit written comments on the proposed regulatory changes by February 13, 2006. Interested persons may submit written engineering analysis and technical data by April 14, 2006. Latefiled comments will be considered to the extent possible. ADDRESSES: Comments should reference Docket No. PHMSA–04–18938 and may be submitted in the following ways: • DOT Web site: https://dms.dot.gov. To submit comments on the DOT electronic docket site, click ‘‘Comment/ Submissions,’’ click ‘‘Continue,’’ fill in the requested information, click ‘‘Continue,’’ enter your comment, then click ‘‘Submit.’’ • Fax: 1–202–493–2251. • Mail: Docket Management System: U.S. Department of Transportation, 400 Seventh Street, SW., Nassif Building, Room PL–401, Washington, DC 20590– 0001. PO 00000 Frm 00051 Fmt 4702 Sfmt 4702 74265 • Hand Delivery: DOT Docket Management System, Room PL–401 on the plaza of the Nassif Building, 400 Seventh Street, SW., Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. • E-Gov Web site: https:// www.Regulations.gov. This site allows the public to enter comments on any Federal Register notice issued by any agency. Instructions: You should identify docket number PHMSA–04–18938 at the beginning of your comments. If you submit your comments by mail, you should send two copies. If you wish to receive PHMSA’s confirmation receipt of your comments, you should include a self-addressed stamped postcard. Internet users may submit comments at https://www.regulations.gov, and may access all comments received by DOT at https://dms.dot.gov by performing a simple search for the docket number. Note: All comments will be posted without changes or edits to https:// dms.dot.gov including any personal information provided. Please see the Privacy Act heading under Section V, Regulatory Analyses and Notices, of the SUPPLEMENTARY INFORMATION. Privacy Act Statement: Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT’s complete Privacy Act Statement in the Federal Register published on April 11, 2000 (70 FR 19477) or you may visit https://dms.dot.gov. FOR FURTHER INFORMATION CONTACT: Shauna Turnbull by phone at (202) 366– 3731 or via e-mail at shauna.turnbull@dot.gov. For questions on technical issues, contact Mike Israni at (202) 366–4571 or via e-mail at mike.israni@dot.gov. SUPPLEMENTARY INFORMATION: I. Background Statutory and Regulatory Requirements The Nation’s existing pipeline infrastructure, much of which is over 50 years old, requires regular safety and environmental reviews to ensure its reliability. To address several statutory mandates and National Transportation Safety Board (NTSB) recommendations on actions to improve pipeline safety, PHMSA 1 issued Integrity Management 1 The former Research and Special Programs Administration (RSPA) was the entity responsible for issuing the hazardous liquid pipeline and gas transmission pipeline integrity management program regulations. RSPA divided into two new agencies on February 20, 2005. The newly formed PHMSA assumed responsibility for pipeline safety and hazardous materials management regulatory oversight. E:\FR\FM\15DEP1.SGM 15DEP1 74266 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules Program (IMP) regulations for operators of hazardous liquid pipelines with more than 500 miles of pipeline (65 FR 75378; Dec. 1, 2000). PHMSA finalized the regulation’s repair criteria provisions on January 14, 2002 (67 FR 1650), and extended the IMP regulations to operators with fewer than 500 miles of hazardous liquid pipeline on January 16, 2002 (67 FR 2136). These regulations are found at 49 CFR 195.452. During development of proposed IMP requirements for operators of gas transmission pipelines, Congress passed the Pipeline Safety Improvement Act of 2002, subsequently codified at 49 U.S.C. 60101 et seq. Section 60109 required issuance of regulations by December 17, 2003, prescribing standards for a gas transmission pipeline operator’s adoption and implementation of an IMP. The statute also prescribed minimum requirements to be included in these programs. PHMSA issued IMP regulations for gas transmission pipelines on December 15, 2003. These regulations are found in 49 CFR Part 192, Subpart O. Both the hazardous liquid pipeline and gas transmission pipeline IMP regulations require operators to continually assess, evaluate, repair, and validate through comprehensive analysis, integrity of pipeline segments in areas where a leak or rupture would do the most damage, such as in populated and environmentally sensitive areas. These areas are called ‘‘High Consequence Areas’’ (HCAs). PHMSA has broad authority under 49 U.S.C. 60102 to issue regulations applying to design, installation, inspection, emergency plans and procedures, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities. The IMP requirements were issued under this authority and addressed the following statutory mandates: • 49 U.S.C. 60109(a)—to prescribe standards establishing criteria for identifying gas pipeline facilities located in high-density population areas and hazardous liquid pipeline facilities that cross waters where a substantial likelihood of commercial navigation exists, located in a high-density population area, or in an area unusually sensitive to environmental damage (USAs); • 49 U.S.C. 60102(f)(2)—to prescribe additional standards requiring the periodic inspection of pipelines in USAs and high-density population areas; • 49 U.S.C. 60102(j)—to survey and assess the effectiveness of emergency flow restricting devices (EFRD) and other procedures, systems, and VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 equipment used to detect and locate hazardous liquid pipeline ruptures and to prescribe regulations on the circumstances where a hazardous liquid pipeline operator must use an EFRD or similar equipment; and • 49 U.S.C. 60109(c)—to issue regulations prescribing standards to direct gas transmission pipeline operators to conduct a risk analysis and adopt and implement an integrity management program. The proposed revisions in this NPRM simply modify several of the requirements in the hazardous liquid pipeline and gas transmission pipeline IMP regulations. Also, 49 U.S.C. 60109(b) requires a pipeline safety standard to be practicable and designed to meet the need for environmental safety and protection. Pursuant to 60109(b)(2), PHMSA considered many factors in issuing revisions proposed in this NPRM. PHMSA must also consider comments received from the public along with comments and recommendations from the Technical Hazardous Liquid Pipeline and Technical Pipeline Safety Standards Committees as appropriate. PHMSA will address public comments and advisory committee comments when a final rule is prepared on these proposed revisions. Hazardous Liquid Pipeline IMP Overview Hazardous liquid pipeline IMP regulations apply to any hazardous liquid or carbon dioxide pipeline that could affect an HCA. Hazardous liquid pipeline HCAs are defined as populated areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. Among other specifications, the regulations require operators to conduct a baseline assessment and periodically evaluate the integrity of each pipeline segment that could affect an HCA. Operators must also remediate, and have a schedule for evaluation and remediation of, anomalous conditions discovered from these assessments. For certain conditions, the regulations prescribe time frames for an operator to remediate the defect. These conditions are categorized into immediate, 60-day, or 180-day repair conditions. Gas Transmission Pipeline IMP Overview Gas transmission pipeline IMP regulations apply to gas transmission pipelines located in HCAs. A gas transmission pipeline HCA is defined by either of two methods: (a) a Class 3 or 4 location and any area outside a Class 3 or 4 location where the Potential PO 00000 Frm 00052 Fmt 4702 Sfmt 4702 Impact Radius is greater than 660 feet (200 meters), and the area within a Potential Impact Circle contains 20 or more buildings intended for human occupancy; or (b) an identified site, which is an area meeting one of three subcriteria: (1) An outside area or open structure occupied by 20 or more people at least 50 days a year (days need not be consecutive); (2) A building occupied by 20 or more people on at least 5 days a week for 10 weeks in a year (days and weeks need not be consecutive); or (3) The area within a Potential Impact Circle containing 20 or more buildings intended for human occupancy (unless the exception in method (a) applies). Gas transmission pipeline operators must complete a baseline assessment and conduct continual integrity assessment of pipeline segments in HCAs and address all anomalous conditions discovered. An operator must remediate anomalies according to a schedule prioritizing conditions for evaluation and remediation. Time frames are specified for certain conditions, categorized as immediate, one-year, or monitored conditions. Industry Petition for IMP Modifications and Clarifications On June 18, 2004, the American Petroleum Institute (API) and the Association of Oil Pipe Lines (hereinafter collectively referred to as ‘‘API’’) petitioned PHMSA for changes to the hazardous liquid pipeline IMP regulations. The petition sought changes in three areas: (1) adding flexibility to reassessment intervals; (2) adding flexibility to scheduling repairs; and (3) providing for notification when an operator is unable to make a repair because of permitting or other problems. On August 27, 2004, PHMSA personnel met with API representatives to further discuss API’s proposed changes; a meeting summary is in the docket. NPRM Changes and Information Request (1) Flexibility in Reassessment Interval. To preserve a pipeline’s integrity, § 195.452(j) requires a continual evaluation and assessment of each hazardous liquid pipeline segment that could affect an HCA. Under § 195.452(j)(3), an operator is required to establish intervals not to exceed five years for continually assessing the pipe’s integrity. The API petition requests the reassessment interval be extended from a maximum of 5 years to E:\FR\FM\15DEP1.SGM 15DEP1 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules not longer than 68 months. API maintains that adding a window of time to complete a reassessment gives operators flexibility when having to factor in events affecting reassessment. Such events could include weather conditions, scheduling difficulties in getting certain tools, species’ life cycle activities, and permitting problems. API’s petition also notes the expanded interval would be consistent with other pipeline safety regulations specifying time frames for completing required activities. PHMSA agrees adding an eight-month window to the hazardous liquid pipeline five-year reassessment interval will give operators flexibility in scheduling and completing reassessment, without compromising pipeline safety. Such a change is consistent with other pipeline safety regulations specifying time frames for an operator to complete an inspection. (2) Scheduling Repairs. API’s petition also recommends modifying the ‘‘Special requirements for scheduling remediation’’ in § 195.452(h)(4) to allow application of engineering judgment and additional flexibility. API suggests an approach aligned with Part 192 gas transmission pipeline IMP repair criteria, such as: • expanding immediate repairs to include any dent with cracking indications (rather than just top side dents with cracking); • removing 3% dents from 60-day conditions; • creating a 365-day condition category; and • creating a monitored conditions category consisting of ‘‘other conditions’’, and some of the 180-day conditions. API gives the following reasons for requesting these revisions to the hazardous liquid pipeline repair criteria: • the designation of 60- and 180-day conditions in Part 195 does not focus on the physical significance of an anomaly based on the likelihood pipe may fail; • data indicate operators are not finding significant 60-day conditions; • the excavation necessary to examine anomalies and to conduct repairs is the most expensive part of the process; operators seek to schedule excavations for repairs as efficiently as possible while still making timely repairs; • the length of time for getting necessary permits and approvals can exceed the required time frames for making repairs; • the extension of 60- and 180-day conditions to 365-day conditions will allow permitting agencies and operators VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 to focus Federal streamlining efforts on those repairs that may pose an immediate risk; • environmental considerations to protect important species will affect operators’ ability to schedule necessary pipeline integrity activities; and • repair criteria based on immediate, scheduled, and monitored repairs would work well for the hazardous liquid pipeline industry, especially considering its high usage of in-line inspection tools. Request for Data PHMSA and API discussed the need for more information (data on types of defects currently requiring remediation within 60 and 180 days), before PHMSA could determine if regulatory or some other action would be needed to address API’s request. To better determine what type of action, if any, is needed PHMSA is requesting data and comments on the following topics: • an identification of the characteristics of defects requiring short-term (60- and 180-day) remediation; • an evaluation of defects to find out which are stable; • a sound engineering or technical basis for checking rather than repairing these defects; and • the development of criteria allowing operators to use logs from internal inspection tool runs to identify stable defects. (3) Notification of Special Circumstances. API believes the hazardous liquid pipeline IMP rule fails to recognize that an operator may not be able to make a repair within a required period. API requests changing the rule to allow an operator to notify PHMSA when the operator has taken all available steps and is still unable to conduct an investigation or repair a specific condition. API maintains such a change would alert PHMSA to the myriad real-world conditions (weather, electrical outage, and permitting requirements) that can interfere with repair periods and would also protect operators from enforcement action for events over which an operator has no control. API further believes notification would help PHMSA recognize patterns potentially affecting pipeline safety, such as new or changed permit criteria. Both the hazardous liquid pipeline (§ 195.452(h)) and gas transmission pipeline (§ 192.933) IMP remediation requirements require an operator to temporarily reduce pressure or to shut down the pipeline until the operator completes repair of an immediate repair condition. Gas transmission pipeline operators are also required to reduce PO 00000 Frm 00053 Fmt 4702 Sfmt 4702 74267 pressure if they cannot meet a specified time limit for making a repair, or to take other action to ensure segment safety. The regulations do not require notification when an operator reduces pressure. Notification is required only when a hazardous liquid pipeline or gas transmission pipeline operator cannot meet its schedule for evaluating and remediating any condition and cannot provide safety though a temporary reduction in operating pressure. Any pressure reduction longer than 365 days must also be justified. PHMSA agrees with API that notifying PHMSA of the reasons for an operator making a pressure reduction would give the agency better information on conditions that could interfere with an operator’s ability to complete remediation of defects found during an integrity assessment. However, the usefulness of such information is not limited to repairs made on hazardous liquid pipelines. Therefore, PHMSA is proposing to revise remediation requirements to require both gas transmission pipeline and hazardous liquid pipeline operators to notify PHMSA when a pressure reduction is made on a segment covered under IMP to remediate a defect, and to provide the reasons for the pressure reduction. Instead of only requiring notification when an operator cannot meet repair schedules and cannot provide safety through a temporary reduction in operating pressure, an operator would be required to notify PHMSA any time it reduces operating pressure to make a repair, and to give the pressure reduction reasons. If a repair takes longer than 365 days, an operator would again have to notify PHMSA and provide the reasons for the delay. Operators would still be required to take further remedial action to ensure pipeline safety when a pressure reduction exceeds 365 days. For gas transmission pipeline operators, State notification requirements would continue to apply for intrastate gas transmission pipelines and interstate gas transmission pipelines in States where PHMSA has an interstate agent agreement. However, we are proposing to delete the requirement for notification of local pipeline safety authorities. PHMSA is not aware of any instance where an intrastate gas transmission pipeline would be regulated by a local authority rather than a State public safety authority. Furthermore, PHMSA interstate agreements are only with State pipeline safety authorities. PHMSA proposes these revisions to get a better understanding of the reasons hazardous liquid pipeline and gas E:\FR\FM\15DEP1.SGM 15DEP1 74268 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules transmission pipeline operators are delayed in making repairs. PHMSA further hopes to work with the U.S. Department of Energy to analyze whether prolonged pressure reductions have potential impact on the Nation’s energy supply. This notification will also give PHMSA better information on: • whether permitting issues are involved in pressure reduction; • what causes schedule delays (permitting, scheduling, other); and • where and under what circumstances PHMSA can help expedite permits for repairs. (4) Formula for Reducing Operating Pressure. Section 195.452(h)(4) requires a hazardous liquid pipeline operator to calculate a temporary reduction in operating pressure using the formula in section 451.7 of ASME/ANSI B31.4 when making an immediate repair. The requirement was meant to ensure an additional safety margin is provided while an operator makes an immediate repair. However, a recent frequently asked question highlighted that this formula does not always apply and may result in a calculated pressure higher than the original operating pressure. In addition, the formula only applies to metal loss anomalies, not to immediate repair conditions not involving metal loss. Therefore, PHMSA proposes to correct the provision by allowing a hazardous liquid pipeline operator to use the ASME/ANSI B31.4 formula only if applicable. If not applicable to the anomaly, or if the formula results in a calculated pressure higher than original operating pressure, an operator would be allowed to use another acceptable means to calculate a pressure reduction. Regulatory Analyses and Notices Executive Order 12866 and DOT Regulatory Policies and Procedures DOT does not consider this action to be a significant regulatory action under section 3(f) of Executive Order 12866 (58 FR 51735; October 4, 1993). This NPRM is nonsignificant under DOT’s regulatory policies and procedures (44 FR 11034; February 26, 1979). PHMSA prepared a Draft Regulatory Evaluation for this NPRM and placed it in the public docket. The proposed changes to add flexibility to scheduling continuous assessment would create ongoing benefits and have no cost effects. These adjustments would create positive net benefits. PHMSA believes the proposed change to the notification requirement for pressure reduction would create added continuing costs, with an estimated six notifications per operator each year. However, notification VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 requirements have no significant cost for either operators or industry overall. The benefits are expected to offset costs. Together, these proposed changes to IMP regulations for hazardous liquid and gas transmission pipelines are expected to create positive net benefits. Regulatory Flexibility Act Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) PHMSA must consider whether a rulemaking would have a significant impact on a substantial number of small entities. The requirements proposed in this NPRM do not apply to a substantial number of small entities. The proposed revisions to the IMP rules will affect hazardous liquid pipeline operators and gas transmission pipeline operators. Most hazardous liquid pipeline operators and gas transmission pipeline operators do not meet the Small Business Administration’s small business definition, which is either 6 million in revenue (for natural gas pipelines under North American Industry Classification System (NAICS) 486210) or 1,500 employees (for crude oil and refined petroleum product pipelines under NAICS 486110 and 486910). Additionally, notification costs per operator are about $194.50 annually. This is less than 0.01 percent of the $6 million gross revenue. This is not a significant burden on pipeline operators, including small businesses. The proposed changes to add flexibility to scheduling continuous assessment would create ongoing benefits and have no cost effects. These modifications would create positive net benefits. The changed notification requirements for pressure reduction would create negligible added costs as well as benefits; however, the benefits are expected to offset costs. Together, these proposed changes to the IMP regulations for hazardous liquid and gas transmission pipelines are expected to create positive net benefits to the affected industry. Based on the cost benefit analysis and the determination that hazardous liquid pipeline and gas transmission pipeline operators do not generally fall into the Small Business Administration’s revenue or employee size guidelines, it is unlikely (under section 605 of the Regulatory Flexibility Act) the proposed regulatory changes will have any significant impact on a substantial number of small entities. PHMSA invites comments on these assumptions. Paperwork Reduction Act This NPRM proposes minimal information collection requirements. Based on information currently PO 00000 Frm 00054 Fmt 4702 Sfmt 4702 available to PHMSA, 74 notifications were submitted by 26 operators over three years. Of these 74 notifications, 36 of them, or about 50 percent, were due to an operator’s inability to meet repair schedules or reduce pressure. The proposed notification modifications will increase notification frequency. PHMSA estimates, on average, the proposed changes will result in six notifications per operator annually. The estimated average time to prepare a notification request is 30 minutes. Consequently, there should be no significant cost or hourly burden on individual operators or the industry because of the notification requirement in this proposal. PHMSA evaluated the NPRM, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), and believes there will be no significant paperwork burden on industry or individual operators because of the NPRM. As required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), PHMSA will present a separate paperwork analysis to the Office of Management and Budget for review. A copy of the analysis will also be entered in the docket. Executive Order 13084 This NPRM has been analyzed under principles and criteria contained in Executive Order 13084 (‘‘Consultation and Coordination with Indian Tribal Governments’’). Because this NPRM does not significantly or uniquely affect communities of Indian tribal governments and does not impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13084 do not apply. Executive Order 13132 PHMSA analyzed this NPRM under principles and criteria contained in Executive Order 13132 (Federalism). None of the proposed actions: (1) Has substantial direct effects on States, relationships between the National Government and the States, or distribution of power and responsibilities among various levels of government; (2) imposes substantial direct compliance costs on States and local governments; or (3) preempts State law. Therefore, the consultation and funding requirements of Executive Order 13132 (64 FR 43255; August 10, 1999) do not apply. Executive Order 13211 This NPRM is not a ‘‘significant energy action’’ under Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use). It is not likely to have a significant adverse effect on E:\FR\FM\15DEP1.SGM 15DEP1 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules supply, distribution, or energy use. Further, the Office of Information and Regulatory Affairs has not designated this NPRM as a significant energy action. Unfunded Mandates This NPRM does not impose unfunded mandates under the 1995 Unfunded Mandates Reform Act. It does not result in costs of $100 million or more to either State, local, or tribal governments, in aggregate, or to the private sector, and is the least burdensome alternative for achieving the NPRM objectives. 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 1500–1508), and DOT Order 5610.1D, and has preliminarily determined this action will not significantly affect human environment quality. The Environmental Assessment is in the Docket. List of Subjects in 49 CFR Parts 192 and 195 Pipeline safety, Reporting and recordkeeping requirements. For the reasons set forth in the preamble, PHMSA proposes to amend 49 CFR parts 192 and 195 as follows: PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS 1. The authority citation for Part 192 continues to read as follows: Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53. 2. Amend § 192.933 by revising paragraphs (a) and (c) to read as follows: § 192.933 What actions must be taken to address integrity issues? (a) General requirements. An operator must take prompt action to address all anomalous conditions that the operator discovers through the integrity assessment. 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 integrity of the pipeline until the next reassessment of the covered segment. (1) Pressure reduction. If an operator is unable to respond within the time VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. If pressure is reduced, an operator must determine the temporary reduction in operating pressure using ASME/ANSI B31G (ibr, see § 192.7) or AGA Pipeline Research Committee Project PR–3–805 (‘‘RSTRENG’’; ibr, see § 192.7) or reduce the operating pressure to a level not exceeding 80 percent of the level at the time the condition was discovered. (See appendix A to this part for information on availability of incorporation by reference information). (i) Notice. An operator must notify PHMSA in accordance with § 192.949 whenever it reduces operating pressure to make a repair under this subpart. This will include any temporary reduction in pressure required by this section. This notice must include the reasons for the pressure reduction. An operator must also notify a State pipeline safety authority when either a covered segment is located in a State where PHMSA has an interstate agent agreement, or an intrastate covered segment is regulated by that State. (ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days, an operator must again notify PHMSA under § 192.949 with the reasons causing the delay. An operator must also notify a State pipeline safety authority when either a covered segment is located in a State where PHMSA has an interstate agent agreement, or an intrastate covered segment is regulated by that State. In addition, an operator must provide a technical justification that the continued pressure restriction will not jeopardize the integrity of the pipeline. (2) [Reserved] * * * * * (c) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule that prioritizes the conditions for evaluation and remediation. Unless a special requirement for remediating certain conditions applies, as provided in paragraph (d) of this section, an operator must follow the schedule in ASME/ ANSI B31.8S (ibr, see § 192.7), section 7, Figure 4. If an operator cannot meet the schedule for any condition, the operator must justify the reasons why it cannot meet the schedule and that the changed schedule will not jeopardize public safety. * * * * * PO 00000 Frm 00055 Fmt 4702 Sfmt 4702 74269 PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE 3. The authority citation for part 195 continues to read as follows: Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118; and 49 CFR 1.53. 4. Amend § 195.452 by revising paragraphs (h)(1), (h)(3), (h)(4)(i) introductory text and the first sentence of paragraph (j)(3) to read as follows: § 195.452 Pipeline integrity management in high consequence areas. * * * * * (h) * * * (1) General requirements. An operator must take prompt action to address all anomalous conditions 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 § 195.422 when making a repair. (i) Pressure reduction. An operator must notify PHMSA in accordance with paragraph (m) of this section whenever it reduces operating pressure to make a repair under this section. This will include any temporary reduction in pressure required by paragraph (h) (4) (i) of this section. This notice must include the reasons for the pressure reduction. (ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days, an operator must again notify PHMSA in accordance with paragraph (m) of this section with the reasons causing the delay. An operator must also take further remedial action to ensure the safety of the pipeline. * * * * * (3) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule that prioritizes the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must justify the reasons why it cannot meet the schedule and that the changed schedule will not jeopardize public safety or environmental protection. (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 operating pressure or shut down the E:\FR\FM\15DEP1.SGM 15DEP1 74270 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in section 451.7 of ASME/ ANSI B31.4 (ibr, see § 195.3), if applicable. If the formula is not applicable to the type of anomaly or the calculated pressure results in 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: * * * * * (j) * * * (3) Assessment intervals. An operator must establish five-year intervals, not to exceed 68 months, for continually assessing the line pipe’s integrity.* * * * * * * * Issued in Washington, DC, on December 12, 2005. Stacey L. Gerard, Associate Administrator for Pipeline Safety. [FR Doc. 05–24061 Filed 12–12–05; 1:29 pm] BILLING CODE 4910–60–P DEPARTMENT OF TRANSPORTATION National Highway Traffic Safety Administration 49 CFR Part 571 [Docket No. NHTSA–2005–21462] RIN 2127–AJ37 Federal Motor Vehicle Safety Standards; Air Brake Systems National Highway Traffic Safety Administration (NHTSA), Department of Transportation. ACTION: Notice of proposed rulemaking (NPRM). AGENCY: SUMMARY: The agency is proposing to amend our air brake standard to improve the stopping distance performance of truck tractors. Based on current safety trend data and brake system technologies for truck tractors, we are proposing to reduce the required stopping distance for these vehicles by 20 to 30 percent. We have tentatively concluded that truck tractors are capable of achieving a reduction in stopping distance within this range with existing technologies. We also discuss research and request comment concerning improving the braking performance of other types of heavy vehicles, i.e., trailers, straight trucks, and buses. The agency may address improved braking performance VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 for these other vehicles in a future rulemaking. You should submit comments early enough to ensure that Docket Management receives them not later than April 14, 2006. ADDRESSES: You may submit comments (identified by the DOT DMS Docket Number) by any of the following methods: • Web site: https://dms.dot.gov. Follow the instructions for submitting comments on the DOT electronic docket site. • Fax: (202) 493–2251. • Mail: Docket Management Facility, U.S. Department of Transportation, 400 Seventh Street, SW., Nassif Building, Room PL–401, Washington, DC 20590– 001. • Hand Delivery: Room PL–401 on the plaza level of the Nassif Building, 400 Seventh Street, SW., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal Holidays. • Federal eRulemaking Portal: Go to https://www.regulations.gov. Follow the online instructions for submitting comments. Instructions: All submissions must include the agency name and docket number or Regulatory Identification Number (RIN) for this rulemaking. For detailed instructions on submitting comments and additional information on the rulemaking process, see the Request for Comments heading under the SUPPLEMENTARY INFORMATION section of this document. Note that all comments received will be posted without change to https://dms.dot.gov, including any personal information provided. You may review DOT’s complete Privacy Act Statement in the Federal Register published on April 11, 2000 (Volume 65, Number 70; Pages 19477–78) or you may visit https:// dms.dot.gov. Docket: For access to the docket to read background documents or comments received, go to https:// dms.dot.gov at any time or to Room PL– 401 on the plaza level of the Nassif Building, 400 Seventh Street, SW., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal Holidays. FOR FURTHER INFORMATION CONTACT: The following persons at the National Highway Traffic Safety Administration: For non-legal issues: Mr. Jeff Woods of the NHTSA Office of Rulemaking at (202) 366–6206. For legal issues: Mr. Christopher Calamita of the NHTSA Office of Chief Counsel at (202) 366–2992. DATES: PO 00000 Frm 00056 Fmt 4702 Sfmt 4702 You may send mail to both of these officials at the National Highway Traffic Safety Administration, 400 Seventh St., SW., Washington, DC 20590. SUPPLEMENTARY INFORMATION: I. Background II. Safety Issues III. Heavy Truck Braking Performance A. NHTSA Research B. Industry Research C. Agency Proposal IV. Benefits and Costs of Improved Stopping Distances V. Lead Time VI. Ongoing and Future Research VII. Request for Comments VIII.Rulemaking Analyses and Notices I. Background On March 10, 1995, we published three final rules as a part of a comprehensive effort to improve the braking ability of medium and heavy vehicles 1 (60 FR 13216 and 60 FR 13287). The major focus of that effort was to improve the directional stability and control of heavy vehicles during braking through antilock brake system (ABS) requirements. However, the 1995 effort also reinstated stopping distance requirements for air-braked vehicles, and established different stopping distances for different types of heavy vehicles. Previous stopping distance requirements for medium and heavy vehicles had been invalidated in 1978 by the United States Court of Appeals for the 9th Circuit because of issues with the reliability of ABS then in use. See, PACCAR v. NHTSA, 573 F.2d 632 (9th Cir. 1978) cert. denied, 439 U.S. 862 (1978). The current stopping distance requirements under Federal Motor Vehicle Safety Standard No. 121, Air brake systems, as established under the 1995 final rule, are determined according to vehicle type. Under the loaded-60-mph stopping distance requirements of FMVSS No. 121, airbraked buses must comply with a stopping distance of 280 feet, air-braked single-unit trucks must comply with a stopping distance of 310 feet, and airbraked truck tractors must comply with a stopping distance requirement of 355 feet.2 Under the unloaded-60-mph 1 Medium and heavy weight vehicles are hydraulic-braked vehicles over 10,000 pounds gross vehicle weight rating (GVWR) (i.e., trucks and buses), and all vehicles with a GVWR greater than 10,000 pounds equipped with air brake systems (i.e., trucks, buses, and trailers); here after referred to collectively as heavy vehicles. Large trucks are a segment of heavy vehicles and are defined as trucks, including truck tractors, with a GVWR greater than 10,000 pounds. 2 For heavy truck tractors (tractors), the current stopping distance test at GVWR is conducted with the tractor coupled to an un-braked control trailer, with weight placed over the fifth wheel of the E:\FR\FM\15DEP1.SGM 15DEP1

Agencies

[Federal Register Volume 70, Number 240 (Thursday, December 15, 2005)]
[Proposed Rules]
[Pages 74265-74270]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-24061]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 192 and 195

[Docket No. PHMSA-04-18938]
RIN 2137-AE07


Integrity Management: Program Modifications and Clarifications--
Request for Comments

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

ACTION: Notice of proposed rulemaking.

-----------------------------------------------------------------------

SUMMARY: PHMSA proposes revisions to the current Pipeline Safety 
Regulations for Pipeline Integrity Management in High Consequence 
Areas. The revisions address a petition from the hazardous liquid 
pipeline industry. The revisions are to: allow more flexibility in 
reassessment intervals for hazardous liquid pipelines by adding an 
eight-month window to the five-year time frame for operators to 
complete reassessment; and require both hazardous liquid pipeline and 
gas transmission pipeline operators to notify PHMSA whenever they 
reduce pipeline pressure to make a repair and to provide reasons for 
pressure reduction. Another notification, including reasons for repair 
delay, would be required when a pressure reduction exceeds 365 days.
    Also, PHMSA proposes to correct existing provisions for calculating 
a pressure reduction when making an immediate repair on a hazardous 
liquid pipeline. The proposed correction would allow operators to use 
another acceptable method to calculate reduced operating pressure when 
a specified formula is not applicable or results in a calculated 
pressure higher than operating pressure.
    Finally, PHMSA seeks the submittal of engineering analyses and 
technical data. These submittals are to provide the basis for modifying 
the required time periods for remediating certain conditions found 
during a hazardous liquid pipeline integrity assessment. PHMSA will use 
this data to evaluate the scope and scale of repair issues to develop 
an accurate basis for determining if any additional flexibility is 
needed in the repair schedules.

DATES: Interested persons may submit written comments on the proposed 
regulatory changes by February 13, 2006. Interested persons may submit 
written engineering analysis and technical data by April 14, 2006. 
Late-filed comments will be considered to the extent possible.

ADDRESSES: Comments should reference Docket No. PHMSA-04-18938 and may 
be submitted in the following ways:
     DOT Web site: https://dms.dot.gov. To submit comments on 
the DOT electronic docket site, click ``Comment/Submissions,'' click 
``Continue,'' fill in the requested information, click ``Continue,'' 
enter your comment, then click ``Submit.''
     Fax: 1-202-493-2251.
     Mail: Docket Management System: U.S. Department of 
Transportation, 400 Seventh Street, SW., Nassif Building, Room PL-401, 
Washington, DC 20590-0001.
     Hand Delivery: DOT Docket Management System, Room PL-401 
on the plaza of the Nassif Building, 400 Seventh Street, SW., 
Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except 
Federal holidays.
     E-Gov Web site: https://www.Regulations.gov. This site 
allows the public to enter comments on any Federal Register notice 
issued by any agency.
    Instructions: You should identify docket number PHMSA-04-18938 at 
the beginning of your comments. If you submit your comments by mail, 
you should send two copies. If you wish to receive PHMSA's confirmation 
receipt of your comments, you should include a self-addressed stamped 
postcard. Internet users may submit comments at https://
www.regulations.gov, and may access all comments received by DOT at 
https://dms.dot.gov by performing a simple search for the docket number. 
Note: All comments will be posted without changes or edits to https://
dms.dot.gov including any personal information provided. Please see the 
Privacy Act heading under Section V, Regulatory Analyses and Notices, 
of the Supplementary Information.
    Privacy Act Statement: Anyone may search the electronic form of all 
comments received for any of our dockets. You may review DOT's complete 
Privacy Act Statement in the Federal Register published on April 11, 
2000 (70 FR 19477) or you may visit https://dms.dot.gov.

FOR FURTHER INFORMATION CONTACT: Shauna Turnbull by phone at (202) 366-
3731 or via e-mail at shauna.turnbull@dot.gov. For questions on 
technical issues, contact Mike Israni at (202) 366-4571 or via e-mail 
at mike.israni@dot.gov.

SUPPLEMENTARY INFORMATION:

I. Background

Statutory and Regulatory Requirements

    The Nation's existing pipeline infrastructure, much of which is 
over 50 years old, requires regular safety and environmental reviews to 
ensure its reliability. To address several statutory mandates and 
National Transportation Safety Board (NTSB) recommendations on actions 
to improve pipeline safety, PHMSA \1\ issued Integrity Management

[[Page 74266]]

Program (IMP) regulations for operators of hazardous liquid pipelines 
with more than 500 miles of pipeline (65 FR 75378; Dec. 1, 2000). PHMSA 
finalized the regulation's repair criteria provisions on January 14, 
2002 (67 FR 1650), and extended the IMP regulations to operators with 
fewer than 500 miles of hazardous liquid pipeline on January 16, 2002 
(67 FR 2136). These regulations are found at 49 CFR 195.452.
---------------------------------------------------------------------------

    \1\ The former Research and Special Programs Administration 
(RSPA) was the entity responsible for issuing the hazardous liquid 
pipeline and gas transmission pipeline integrity management program 
regulations. RSPA divided into two new agencies on February 20, 
2005. The newly formed PHMSA assumed responsibility for pipeline 
safety and hazardous materials management regulatory oversight.
---------------------------------------------------------------------------

    During development of proposed IMP requirements for operators of 
gas transmission pipelines, Congress passed the Pipeline Safety 
Improvement Act of 2002, subsequently codified at 49 U.S.C. 60101 et 
seq. Section 60109 required issuance of regulations by December 17, 
2003, prescribing standards for a gas transmission pipeline operator's 
adoption and implementation of an IMP. The statute also prescribed 
minimum requirements to be included in these programs.
    PHMSA issued IMP regulations for gas transmission pipelines on 
December 15, 2003. These regulations are found in 49 CFR Part 192, 
Subpart O. Both the hazardous liquid pipeline and gas transmission 
pipeline IMP regulations require operators to continually assess, 
evaluate, repair, and validate through comprehensive analysis, 
integrity of pipeline segments in areas where a leak or rupture would 
do the most damage, such as in populated and environmentally sensitive 
areas. These areas are called ``High Consequence Areas'' (HCAs).
    PHMSA has broad authority under 49 U.S.C. 60102 to issue 
regulations applying to design, installation, inspection, emergency 
plans and procedures, testing, construction, extension, operation, 
replacement, and maintenance of pipeline facilities. The IMP 
requirements were issued under this authority and addressed the 
following statutory mandates:
     49 U.S.C. 60109(a)--to prescribe standards establishing 
criteria for identifying gas pipeline facilities located in high-
density population areas and hazardous liquid pipeline facilities that 
cross waters where a substantial likelihood of commercial navigation 
exists, located in a high-density population area, or in an area 
unusually sensitive to environmental damage (USAs);
     49 U.S.C. 60102(f)(2)--to prescribe additional standards 
requiring the periodic inspection of pipelines in USAs and high-density 
population areas;
     49 U.S.C. 60102(j)--to survey and assess the effectiveness 
of emergency flow restricting devices (EFRD) and other procedures, 
systems, and equipment used to detect and locate hazardous liquid 
pipeline ruptures and to prescribe regulations on the circumstances 
where a hazardous liquid pipeline operator must use an EFRD or similar 
equipment; and
     49 U.S.C. 60109(c)--to issue regulations prescribing 
standards to direct gas transmission pipeline operators to conduct a 
risk analysis and adopt and implement an integrity management program.
    The proposed revisions in this NPRM simply modify several of the 
requirements in the hazardous liquid pipeline and gas transmission 
pipeline IMP regulations.
    Also, 49 U.S.C. 60109(b) requires a pipeline safety standard to be 
practicable and designed to meet the need for environmental safety and 
protection. Pursuant to 60109(b)(2), PHMSA considered many factors in 
issuing revisions proposed in this NPRM. PHMSA must also consider 
comments received from the public along with comments and 
recommendations from the Technical Hazardous Liquid Pipeline and 
Technical Pipeline Safety Standards Committees as appropriate. PHMSA 
will address public comments and advisory committee comments when a 
final rule is prepared on these proposed revisions.

Hazardous Liquid Pipeline IMP Overview

    Hazardous liquid pipeline IMP regulations apply to any hazardous 
liquid or carbon dioxide pipeline that could affect an HCA. Hazardous 
liquid pipeline HCAs are defined as populated areas, areas unusually 
sensitive to environmental damage, and commercially navigable 
waterways. Among other specifications, the regulations require 
operators to conduct a baseline assessment and periodically evaluate 
the integrity of each pipeline segment that could affect an HCA. 
Operators must also remediate, and have a schedule for evaluation and 
remediation of, anomalous conditions discovered from these assessments. 
For certain conditions, the regulations prescribe time frames for an 
operator to remediate the defect. These conditions are categorized into 
immediate, 60-day, or 180-day repair conditions.

Gas Transmission Pipeline IMP Overview

    Gas transmission pipeline IMP regulations apply to gas transmission 
pipelines located in HCAs. A gas transmission pipeline HCA is defined 
by either of two methods: (a) a Class 3 or 4 location and any area 
outside a Class 3 or 4 location where the Potential Impact Radius is 
greater than 660 feet (200 meters), and the area within a Potential 
Impact Circle contains 20 or more buildings intended for human 
occupancy; or (b) an identified site, which is an area meeting one of 
three subcriteria:
    (1) An outside area or open structure occupied by 20 or more people 
at least 50 days a year (days need not be consecutive);
    (2) A building occupied by 20 or more people on at least 5 days a 
week for 10 weeks in a year (days and weeks need not be consecutive); 
or
    (3) The area within a Potential Impact Circle containing 20 or more 
buildings intended for human occupancy (unless the exception in method 
(a) applies).
    Gas transmission pipeline operators must complete a baseline 
assessment and conduct continual integrity assessment of pipeline 
segments in HCAs and address all anomalous conditions discovered. An 
operator must remediate anomalies according to a schedule prioritizing 
conditions for evaluation and remediation. Time frames are specified 
for certain conditions, categorized as immediate, one-year, or 
monitored conditions.

Industry Petition for IMP Modifications and Clarifications

    On June 18, 2004, the American Petroleum Institute (API) and the 
Association of Oil Pipe Lines (hereinafter collectively referred to as 
``API'') petitioned PHMSA for changes to the hazardous liquid pipeline 
IMP regulations. The petition sought changes in three areas:
    (1) adding flexibility to reassessment intervals;
    (2) adding flexibility to scheduling repairs; and
    (3) providing for notification when an operator is unable to make a 
repair because of permitting or other problems.
    On August 27, 2004, PHMSA personnel met with API representatives to 
further discuss API's proposed changes; a meeting summary is in the 
docket.

NPRM Changes and Information Request

    (1) Flexibility in Reassessment Interval. To preserve a pipeline's 
integrity, Sec.  195.452(j) requires a continual evaluation and 
assessment of each hazardous liquid pipeline segment that could affect 
an HCA. Under Sec.  195.452(j)(3), an operator is required to establish 
intervals not to exceed five years for continually assessing the pipe's 
integrity. The API petition requests the reassessment interval be 
extended from a maximum of 5 years to

[[Page 74267]]

not longer than 68 months. API maintains that adding a window of time 
to complete a reassessment gives operators flexibility when having to 
factor in events affecting reassessment. Such events could include 
weather conditions, scheduling difficulties in getting certain tools, 
species' life cycle activities, and permitting problems. API's petition 
also notes the expanded interval would be consistent with other 
pipeline safety regulations specifying time frames for completing 
required activities.
    PHMSA agrees adding an eight-month window to the hazardous liquid 
pipeline five-year reassessment interval will give operators 
flexibility in scheduling and completing reassessment, without 
compromising pipeline safety. Such a change is consistent with other 
pipeline safety regulations specifying time frames for an operator to 
complete an inspection.
    (2) Scheduling Repairs. API's petition also recommends modifying 
the ``Special requirements for scheduling remediation'' in Sec.  
195.452(h)(4) to allow application of engineering judgment and 
additional flexibility. API suggests an approach aligned with Part 192 
gas transmission pipeline IMP repair criteria, such as:
     expanding immediate repairs to include any dent with 
cracking indications (rather than just top side dents with cracking);
     removing 3% dents from 60-day conditions;
     creating a 365-day condition category; and
     creating a monitored conditions category consisting of 
``other conditions'', and some of the 180-day conditions.
    API gives the following reasons for requesting these revisions to 
the hazardous liquid pipeline repair criteria:
     the designation of 60- and 180-day conditions in Part 195 
does not focus on the physical significance of an anomaly based on the 
likelihood pipe may fail;
     data indicate operators are not finding significant 60-day 
conditions;
     the excavation necessary to examine anomalies and to 
conduct repairs is the most expensive part of the process; operators 
seek to schedule excavations for repairs as efficiently as possible 
while still making timely repairs;
     the length of time for getting necessary permits and 
approvals can exceed the required time frames for making repairs;
     the extension of 60- and 180-day conditions to 365-day 
conditions will allow permitting agencies and operators to focus 
Federal streamlining efforts on those repairs that may pose an 
immediate risk;
     environmental considerations to protect important species 
will affect operators' ability to schedule necessary pipeline integrity 
activities; and
     repair criteria based on immediate, scheduled, and 
monitored repairs would work well for the hazardous liquid pipeline 
industry, especially considering its high usage of in-line inspection 
tools.

Request for Data

    PHMSA and API discussed the need for more information (data on 
types of defects currently requiring remediation within 60 and 180 
days), before PHMSA could determine if regulatory or some other action 
would be needed to address API's request. To better determine what type 
of action, if any, is needed PHMSA is requesting data and comments on 
the following topics:
     an identification of the characteristics of defects 
requiring short-term (60- and 180-day) remediation;
     an evaluation of defects to find out which are stable;
     a sound engineering or technical basis for checking rather 
than repairing these defects; and
     the development of criteria allowing operators to use logs 
from internal inspection tool runs to identify stable defects.
    (3) Notification of Special Circumstances. API believes the 
hazardous liquid pipeline IMP rule fails to recognize that an operator 
may not be able to make a repair within a required period. API requests 
changing the rule to allow an operator to notify PHMSA when the 
operator has taken all available steps and is still unable to conduct 
an investigation or repair a specific condition. API maintains such a 
change would alert PHMSA to the myriad real-world conditions (weather, 
electrical outage, and permitting requirements) that can interfere with 
repair periods and would also protect operators from enforcement action 
for events over which an operator has no control. API further believes 
notification would help PHMSA recognize patterns potentially affecting 
pipeline safety, such as new or changed permit criteria.
    Both the hazardous liquid pipeline (Sec.  195.452(h)) and gas 
transmission pipeline (Sec.  192.933) IMP remediation requirements 
require an operator to temporarily reduce pressure or to shut down the 
pipeline until the operator completes repair of an immediate repair 
condition. Gas transmission pipeline operators are also required to 
reduce pressure if they cannot meet a specified time limit for making a 
repair, or to take other action to ensure segment safety. The 
regulations do not require notification when an operator reduces 
pressure. Notification is required only when a hazardous liquid 
pipeline or gas transmission pipeline operator cannot meet its schedule 
for evaluating and remediating any condition and cannot provide safety 
though a temporary reduction in operating pressure. Any pressure 
reduction longer than 365 days must also be justified.
    PHMSA agrees with API that notifying PHMSA of the reasons for an 
operator making a pressure reduction would give the agency better 
information on conditions that could interfere with an operator's 
ability to complete remediation of defects found during an integrity 
assessment. However, the usefulness of such information is not limited 
to repairs made on hazardous liquid pipelines. Therefore, PHMSA is 
proposing to revise remediation requirements to require both gas 
transmission pipeline and hazardous liquid pipeline operators to notify 
PHMSA when a pressure reduction is made on a segment covered under IMP 
to remediate a defect, and to provide the reasons for the pressure 
reduction. Instead of only requiring notification when an operator 
cannot meet repair schedules and cannot provide safety through a 
temporary reduction in operating pressure, an operator would be 
required to notify PHMSA any time it reduces operating pressure to make 
a repair, and to give the pressure reduction reasons. If a repair takes 
longer than 365 days, an operator would again have to notify PHMSA and 
provide the reasons for the delay. Operators would still be required to 
take further remedial action to ensure pipeline safety when a pressure 
reduction exceeds 365 days.
    For gas transmission pipeline operators, State notification 
requirements would continue to apply for intrastate gas transmission 
pipelines and interstate gas transmission pipelines in States where 
PHMSA has an interstate agent agreement. However, we are proposing to 
delete the requirement for notification of local pipeline safety 
authorities. PHMSA is not aware of any instance where an intrastate gas 
transmission pipeline would be regulated by a local authority rather 
than a State public safety authority. Furthermore, PHMSA interstate 
agreements are only with State pipeline safety authorities.
    PHMSA proposes these revisions to get a better understanding of the 
reasons hazardous liquid pipeline and gas

[[Page 74268]]

transmission pipeline operators are delayed in making repairs. PHMSA 
further hopes to work with the U.S. Department of Energy to analyze 
whether prolonged pressure reductions have potential impact on the 
Nation's energy supply. This notification will also give PHMSA better 
information on:
     whether permitting issues are involved in pressure 
reduction;
     what causes schedule delays (permitting, scheduling, 
other); and
     where and under what circumstances PHMSA can help expedite 
permits for repairs.
    (4) Formula for Reducing Operating Pressure. Section 195.452(h)(4) 
requires a hazardous liquid pipeline operator to calculate a temporary 
reduction in operating pressure using the formula in section 451.7 of 
ASME/ANSI B31.4 when making an immediate repair. The requirement was 
meant to ensure an additional safety margin is provided while an 
operator makes an immediate repair. However, a recent frequently asked 
question highlighted that this formula does not always apply and may 
result in a calculated pressure higher than the original operating 
pressure. In addition, the formula only applies to metal loss 
anomalies, not to immediate repair conditions not involving metal loss. 
Therefore, PHMSA proposes to correct the provision by allowing a 
hazardous liquid pipeline operator to use the ASME/ANSI B31.4 formula 
only if applicable. If not applicable to the anomaly, or if the formula 
results in a calculated pressure higher than original operating 
pressure, an operator would be allowed to use another acceptable means 
to calculate a pressure reduction.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Regulatory Policies and Procedures

    DOT does not consider this action to be a significant regulatory 
action under section 3(f) of Executive Order 12866 (58 FR 51735; 
October 4, 1993). This NPRM is nonsignificant under DOT's regulatory 
policies and procedures (44 FR 11034; February 26, 1979). PHMSA 
prepared a Draft Regulatory Evaluation for this NPRM and placed it in 
the public docket.
    The proposed changes to add flexibility to scheduling continuous 
assessment would create ongoing benefits and have no cost effects. 
These adjustments would create positive net benefits. PHMSA believes 
the proposed change to the notification requirement for pressure 
reduction would create added continuing costs, with an estimated six 
notifications per operator each year. However, notification 
requirements have no significant cost for either operators or industry 
overall. The benefits are expected to offset costs. Together, these 
proposed changes to IMP regulations for hazardous liquid and gas 
transmission pipelines are expected to create positive net benefits.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) PHMSA 
must consider whether a rulemaking would have a significant impact on a 
substantial number of small entities. The requirements proposed in this 
NPRM do not apply to a substantial number of small entities. The 
proposed revisions to the IMP rules will affect hazardous liquid 
pipeline operators and gas transmission pipeline operators. Most 
hazardous liquid pipeline operators and gas transmission pipeline 
operators do not meet the Small Business Administration's small 
business definition, which is either 6 million in revenue (for natural 
gas pipelines under North American Industry Classification System 
(NAICS) 486210) or 1,500 employees (for crude oil and refined petroleum 
product pipelines under NAICS 486110 and 486910). Additionally, 
notification costs per operator are about $194.50 annually. This is 
less than 0.01 percent of the $6 million gross revenue. This is not a 
significant burden on pipeline operators, including small businesses.
    The proposed changes to add flexibility to scheduling continuous 
assessment would create ongoing benefits and have no cost effects. 
These modifications would create positive net benefits. The changed 
notification requirements for pressure reduction would create 
negligible added costs as well as benefits; however, the benefits are 
expected to offset costs. Together, these proposed changes to the IMP 
regulations for hazardous liquid and gas transmission pipelines are 
expected to create positive net benefits to the affected industry.
    Based on the cost benefit analysis and the determination that 
hazardous liquid pipeline and gas transmission pipeline operators do 
not generally fall into the Small Business Administration's revenue or 
employee size guidelines, it is unlikely (under section 605 of the 
Regulatory Flexibility Act) the proposed regulatory changes will have 
any significant impact on a substantial number of small entities. PHMSA 
invites comments on these assumptions.

Paperwork Reduction Act

    This NPRM proposes minimal information collection requirements. 
Based on information currently available to PHMSA, 74 notifications 
were submitted by 26 operators over three years. Of these 74 
notifications, 36 of them, or about 50 percent, were due to an 
operator's inability to meet repair schedules or reduce pressure. The 
proposed notification modifications will increase notification 
frequency. PHMSA estimates, on average, the proposed changes will 
result in six notifications per operator annually. The estimated 
average time to prepare a notification request is 30 minutes. 
Consequently, there should be no significant cost or hourly burden on 
individual operators or the industry because of the notification 
requirement in this proposal. PHMSA evaluated the NPRM, as required by 
the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), and believes 
there will be no significant paperwork burden on industry or individual 
operators because of the NPRM. As required by the Paperwork Reduction 
Act of 1995 (44 U.S.C. 3507(d)), PHMSA will present a separate 
paperwork analysis to the Office of Management and Budget for review. A 
copy of the analysis will also be entered in the docket.

Executive Order 13084

    This NPRM has been analyzed under principles and criteria contained 
in Executive Order 13084 (``Consultation and Coordination with Indian 
Tribal Governments''). Because this NPRM does not significantly or 
uniquely affect communities of Indian tribal governments and does not 
impose substantial direct compliance costs, the funding and 
consultation requirements of Executive Order 13084 do not apply.

Executive Order 13132

    PHMSA analyzed this NPRM under principles and criteria contained in 
Executive Order 13132 (Federalism). None of the proposed actions: (1) 
Has substantial direct effects on States, relationships between the 
National Government and the States, or distribution of power and 
responsibilities among various levels of government; (2) imposes 
substantial direct compliance costs on States and local governments; or 
(3) preempts State law. Therefore, the consultation and funding 
requirements of Executive Order 13132 (64 FR 43255; August 10, 1999) do 
not apply.

Executive Order 13211

    This NPRM is not a ``significant energy action'' under Executive 
Order 13211 (Actions Concerning Regulations That Significantly Affect 
Energy Supply, Distribution, or Use). It is not likely to have a 
significant adverse effect on

[[Page 74269]]

supply, distribution, or energy use. Further, the Office of Information 
and Regulatory Affairs has not designated this NPRM as a significant 
energy action.

Unfunded Mandates

    This NPRM does not impose unfunded mandates under the 1995 Unfunded 
Mandates Reform Act. It does not result in costs of $100 million or 
more to either State, local, or tribal governments, in aggregate, or to 
the private sector, and is the least burdensome alternative for 
achieving the NPRM objectives.

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 1500-1508), and DOT Order 
5610.1D, and has preliminarily determined this action will not 
significantly affect human environment quality. The Environmental 
Assessment is in the Docket.

List of Subjects in 49 CFR Parts 192 and 195

    Pipeline safety, Reporting and recordkeeping requirements.

    For the reasons set forth in the preamble, PHMSA proposes to amend 
49 CFR parts 192 and 195 as follows:

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

    1. The authority citation for Part 192 continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, and 60118; and 49 CFR 1.53.

    2. Amend Sec.  192.933 by revising paragraphs (a) and (c) to read 
as follows:


Sec.  192.933  What actions must be taken to address integrity issues?

    (a) General requirements. An operator must take prompt action to 
address all anomalous conditions that the operator discovers through 
the integrity assessment. 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 integrity of the pipeline until the 
next reassessment of the covered segment.
    (1) Pressure reduction. If an operator is unable to respond within 
the time limits for certain conditions specified in this section, the 
operator must temporarily reduce the operating pressure of the pipeline 
or take other action that ensures the safety of the covered segment. If 
pressure is reduced, an operator must determine the temporary reduction 
in operating pressure using ASME/ANSI B31G (ibr, see Sec.  192.7) or 
AGA Pipeline Research Committee Project PR-3-805 (``RSTRENG''; ibr, see 
Sec.  192.7) or reduce the operating pressure to a level not exceeding 
80 percent of the level at the time the condition was discovered. (See 
appendix A to this part for information on availability of 
incorporation by reference information).
    (i) Notice. An operator must notify PHMSA in accordance with Sec.  
192.949 whenever it reduces operating pressure to make a repair under 
this subpart. This will include any temporary reduction in pressure 
required by this section. This notice must include the reasons for the 
pressure reduction. An operator must also notify a State pipeline 
safety authority when either a covered segment is located in a State 
where PHMSA has an interstate agent agreement, or an intrastate covered 
segment is regulated by that State.
    (ii) Long-term pressure reduction. When a pressure reduction 
exceeds 365 days, an operator must again notify PHMSA under Sec.  
192.949 with the reasons causing the delay. An operator must also 
notify a State pipeline safety authority when either a covered segment 
is located in a State where PHMSA has an interstate agent agreement, or 
an intrastate covered segment is regulated by that State. In addition, 
an operator must provide a technical justification that the continued 
pressure restriction will not jeopardize the integrity of the pipeline.
    (2) [Reserved]
* * * * *
    (c) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule that 
prioritizes the conditions for evaluation and remediation. Unless a 
special requirement for remediating certain conditions applies, as 
provided in paragraph (d) of this section, an operator must follow the 
schedule in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 7, Figure 
4. If an operator cannot meet the schedule for any condition, the 
operator must justify the reasons why it cannot meet the schedule and 
that the changed schedule will not jeopardize public safety.
* * * * *

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

    3. The authority citation for part 195 continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118; 
and 49 CFR 1.53.

    4. Amend Sec.  195.452 by revising paragraphs (h)(1), (h)(3), 
(h)(4)(i) introductory text and the first sentence of paragraph 
(j)(3) to read as follows:


Sec.  195.452  Pipeline integrity management in high consequence areas.

* * * * *
    (h) * * *
    (1) General requirements. An operator must take prompt action to 
address all anomalous conditions 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 Sec.  195.422 
when making a repair.
    (i) Pressure reduction. An operator must notify PHMSA in accordance 
with paragraph (m) of this section whenever it reduces operating 
pressure to make a repair under this section. This will include any 
temporary reduction in pressure required by paragraph (h) (4) (i) of 
this section. This notice must include the reasons for the pressure 
reduction.
    (ii) Long-term pressure reduction. When a pressure reduction 
exceeds 365 days, an operator must again notify PHMSA in accordance 
with paragraph (m) of this section with the reasons causing the delay. 
An operator must also take further remedial action to ensure the safety 
of the pipeline.
* * * * *
    (3) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule that 
prioritizes the conditions for evaluation and remediation. If an 
operator cannot meet the schedule for any condition, the operator must 
justify the reasons why it cannot meet the schedule and that the 
changed schedule will not jeopardize public safety or environmental 
protection.
    (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 operating pressure or shut down the

[[Page 74270]]

pipeline until the operator completes the repair of these conditions. 
An operator must calculate the temporary reduction in operating 
pressure using the formula in section 451.7 of ASME/ANSI B31.4 (ibr, 
see Sec.  195.3), if applicable. If the formula is not applicable to 
the type of anomaly or the calculated pressure results in 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:
* * * * *
    (j) * * *
    (3) Assessment intervals. An operator must establish five-year 
intervals, not to exceed 68 months, for continually assessing the line 
pipe's integrity.* * *
* * * * *

    Issued in Washington, DC, on December 12, 2005.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 05-24061 Filed 12-12-05; 1:29 pm]
BILLING CODE 4910-60-P