80 FR 12762 - Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration Federal Register Volume 80, Issue 47 (March 11, 2015)
Pipeline and Hazardous Materials Safety Administration
Federal Register Volume 80, Issue 47 (March 11, 2015)
| Page Range | 12762-12781 | |
| FR Document | 2015-04440 |
[Federal Register Volume 80, Number 47 (Wednesday, March 11, 2015)] [Rules and Regulations] [Pages 12762-12781] From the Federal Register Online [www.thefederalregister.org] [FR Doc No: 2015-04440] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 191, 192, and 195 [Docket No. PHMSA-2010-0026; Amdt. Nos. 191-23; 192-120; 195-100] RIN 2137-AE59 Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: PHMSA is amending the pipeline safety regulations to make miscellaneous changes that update and clarify certain regulatory requirements. These amendments address several subject matter areas including the performance of post-construction inspections, leak surveys of Type B onshore gas gathering lines, qualifying plastic pipe joiners, regulation of ethanol, transportation of pipe, filing of offshore pipeline condition reports, and calculation of pressure reductions for hazardous liquid pipeline anomalies. The changes are addressed on an individual basis and, where appropriate, made applicable to the safety standards [[Page 12763]] for both gas and hazardous liquid pipelines. Editorial changes are also included. DATES: The effective date of these amendments is October 1, 2015. Immediate compliance with these amendments is authorized. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of March 6, 2015. FOR FURTHER INFORMATION CONTACT: Kay McIver, Transportation Specialist, by telephone at 202-366-0113, or by electronic mail at [email protected]. SUPPLEMENTARY INFORMATION: I. Background A. Notice of Proposed Rulemaking On November 29, 2011, PHMSA published a Notice of Proposed Rulemaking (NPRM) under the docket, PHMSA-2010-0026, (76 FR 73570), notifying the public of the proposed changes to 49 CFR parts 191, 192, and 195. We allowed an initial 90-day comment period, but based on requests from several pipeline trade associations, the comment period was extended from February 3, 2012, to March 6, 2012, (77 FR 5472). Most of the amendments proposed in the NPRM were intended to provide relief to industry by eliminating, revising, clarifying, or relaxing regulatory requirements. B. Advisory Committee Meetings On July 11 and 12, 2012, the Technical Pipeline Safety Standards Committee (commonly referred to as the Gas Pipeline Advisory Committee (GPAC)) and the Technical Hazardous Liquid Pipeline Safety Standards Committee (commonly referred to as the Liquid Pipeline Advisory Committee (LPAC)), met jointly at the Marriott Hotel at Metro Center in Washington, DC. The Pipeline Advisory Committees (PACs) are statutorily mandated advisory committees that advise PHMSA on proposed safety standards, risk assessments and safety policies for natural gas pipelines and hazardous liquid pipelines. The PACs were established under the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 1-16) and the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). Each committee consists of 15 members, with membership divided among the Federal and state agencies, the regulated industry and the public. The PACs advise PHMSA on the technical feasibility, practicability and cost-effectiveness of each proposed pipeline safety standard. During the meeting, the PACs considered the NPRM and discussed the various comments and edits proposed by the pipeline industry and the public regarding changes to the regulations. The PACs recommended PHMSA adopt the following proposals with minor or no changes to the regulatory text:Leak Surveys for Type B Gathering Lines; Qualifying Plastic Pipe Joiners; Regulating the Transportation of Ethanol by Pipeline; Transportation of Pipe; Threading Copper Pipe; Offshore Pipeline Condition Reports; Alternative Maximum Allowable Operating Pressure (MAOP) Notifications; National Pipeline Mapping System; Welders vs. Welding Operators; Components Fabricated by Welding; and Editorial Amendments. The PACs recommended PHMSA adopt the following proposals with changes to the regulatory text: Responsibility to Conduct Construction Inspections; Mill Hydrostatic Tests for Pipe to Operate at Alternative MAOP; Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies; and Testing Components other than Pipe Installed in Low- Pressure Gas Pipelines. The PACs recommended that PHMSA not adopt the proposed changes to: Limitation of Indirect Costs in State Grants; and Odorization of gas. This Final Rule adopts the recommendations of the PACs. Additional discussion of the amendments and associated comments of the PACs are provided below: II. Proposals Addressed in This Final Rule 1. Responsibility to Conduct Construction Inspections. 2. Leak Surveys for Type B Gathering Lines. 3. Qualifying Plastic Pipe Joiners. 4. Mill Hydrostatic Tests for Pipe to Operate at Alternative MAOP. 5. Regulating the Transportation of Ethanol by Pipeline. 6. Limitation of Indirect Costs in State Grants. 7. Transportation of Pipe. 8. Threading Copper Pipe. 9. Offshore Pipeline Condition Reports. 10. Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies. 11. Testing Components other than Pipe Installed in Low-Pressure Gas Pipelines. 12. Alternative MAOP Notifications. 13. National Pipeline Mapping System. 14. Welders vs. Welding Operators. 15. Components Fabricated by Welding. 16. Odorization of Gas. 17. Editorial Amendments. III. Commenters to the Rule. PHMSA received a total of 42 comments on the NPRM, to include: 15 from pipeline trade associations. 17 from pipeline operators. 3 from pipeline manufacturers. 3 from states and municipalities. 1 from a Federal source (the National Transportation Safety Board (NTSB)). 3 from private organizations/citizens. IV. Discussion of Public Comments on Individual Issues In this section, PHMSA discusses the changes proposed in the NPRM and the comments received in response to the NPRM. Based on an assessment of the proposed changes and the comments received, PHMSA identifies the proposals that are adopted in this Final Rule. (1) Responsibility to Conduct Construction Inspections Sec. Sec. 192.305 and 195.204. Proposal: PHMSA proposed to revise Sec. 192.305 to specify that a transmission pipeline or main cannot be inspected by someone who participated in its construction. This proposal was based, in part, on a petition (Docket No. PHMSA-2010-0026) from the National Association of Pipeline Safety Representatives (NAPSR),\1\ that suggested that contractors who install a transmission line or main should be prohibited from inspecting their own work for compliance purposes. This petition was also based on the experiences of NAPSR members concerned with the poor quality of construction by unsupervised contractors. --------------------------------------------------------------------------- \1\ NAPSR is a non-profit organization of state pipeline safety personnel who serve to promote pipeline safety in the United States and its territories. Its membership includes the staff manager responsible for regulating pipeline safety from each state that is certified to do so or conducts inspections under an agreement with DOT in lieu of certification. --------------------------------------------------------------------------- PHMSA agreed with NAPSR but recognized that the same concerns should apply to non-contractor pipeline personnel and to hazardous liquid lines. Accordingly, PHMSA proposed to revise Sec. Sec. 192.305 and 195.204 to specify that a transmission pipeline main, or pipeline [[Page 12764]] system, cannot be inspected by someone who participated in its construction. Comments: This topic was the most controversial of all the proposed items. Comments included the following concerns and recommendations: The proposed rule will result in significant cost impact to operators; The proposal is overly burdensome economically and has the potential to compromise site safety due to additional personnel, congestion, inattention, carelessness and unnecessary overhead expenses; The proposed amendment is clearly a significant regulatory action and is inappropriately included in a non-significant rulemaking and should be considered in a separate rulemaking; The proposed language does not differentiate between an operator's employee and a contractor's employee; PHMSA should clarify the meaning of ``person participating in the construction'' of a pipeline; Inspection and new construction should be an Operator Qualification (OQ) task; Prohibiting any ``person'' involved in the construction of a pipeline could be interpreted to prohibit any other municipal employee from performing inspection; and PHMSA should re-define ``a person who participated'' in the construction of the pipeline. NAPSR commented that their resolution was intended to preclude operators from allowing contractor personnel to self-inspect their own work and was based on its members' experience with poor quality of construction by unsupervised contractors. Members of the Association of Oil Pipelines (AOPL) said they do not agree with the statement that ``the proposed rule does not impose any compliance, recordkeeping or other reporting requirement.'' AOPL said the proposed change to Sec. 192.305 will result in significant cost to the operators. In addition, AOPL asserted that the proposal is overly burdensome economically and has the potential to compromise site safety due to additional personnel, congestion, inattention, carelessness and unnecessary overhead expense. The American Gas Association (AGA) noted that PHMSA has failed to provide an analysis to support the significant expansion of the construction inspection revision to all entities and personnel encompassed in the Sec. 192.3 definition of ``person.'' Another commenter noted that PHMSA did not provide a basis for its conclusion on construction inspection and PHMSA's proposed rule does not address the same concerns as NAPSR. The Interstate Natural Gas Association of America (INGAA) noted that instead of adopting the proposed amendment, which increases regulatory confusion and adds to the issues already surrounding construction, PHMSA should convene a public hearing or workshop to develop the fundamental regulatory changes needed to align PHMSA's policy objectives with common pipeline configurations. Response: Consistent with the petition from NAPSR, PHMSA proposed to revise Sec. Sec. 192.305 and 195.204 to prohibit individuals involved in the construction of a transmission line, main or pipeline system from inspecting his or her own work. These inspections are important because transmission pipelines and mains are generally buried after construction. Subsequent examinations often involve a difficult excavation process. PHMSA believes that allowing individuals to inspect their own work defeats, in part, the measure of safety garnered from such inspections. PHMSA was not intending to require third party inspections or attempting to prohibit any person from a company to inspect the work of another person from the same company. The PACs did not agree with the proposed language. There was considerable discussion on the use of alternative language proposed by INGAA and the original language from the NAPSR petition. Following the discussion, the PACs agreed on the revised language for gas and hazardous liquid pipelines. After reviewing the PACs' recommendations and evaluating public comments, PHMSA has adopted language that more clearly identifies the types of individuals who should be excluded from the required inspections, (i.e., the individual who performed the construction task that requires inspection). In regard to the comments that dealt with costs and the significance of the rule, PHMSA believes that the commenters overstated the impact of the proposal. (2) Leak Surveys for Type B Gathering Lines Sec. 192.9. Proposal: In the NPRM, PHMSA proposed that operators of Type B gathering lines must perform leak surveys in accordance with Sec. 192.706 and fix any leaks discovered. Operators of Type B gathering lines currently must ensure that any new or substantially changed Type B line complies with the design, installation, construction, and initial testing and inspection requirements for transmission lines and, if of metallic construction, comply with the corrosion control requirements for transmission lines. Operators must also include Type B gathering lines in their damage prevention and public education programs, establish the MAOP of those lines under Sec. 192.619, and comply with the requirements for maintaining and installing line markers that apply to transmission lines. Comments: The Texas Pipeline Association (TPA) suggested that if PHMSA decided to move forward with the proposal to survey Type B lines, then several topics would need to be addressed to assure the reasonableness of the proposed regulation. TPA suggested that: PHMSA share any supporting information provided by NAPSR to show that leaks are the primary hazard for Type B gathering pipelines; Section 21 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 requires the Secretary of Transportation to review the existing Federal and state regulations for gathering pipelines to determine their sufficiency to ensure the safety of such lines. As such, PHMSA should not move forward with additional regulatory requirements for Type B gathering lines since Congress has mandated a review of the sufficiency of existing regulations; The docket contains no supporting evidence to show that the proposed amendment is based on facts and not speculation; Excavation damage may pose a greater risk than leaks in Type B gathering lines; PHMSA should develop estimates of the cost of compliance for affected operators; The economic impact may exceed the threshold for a non- significant regulatory action; and If PHMSA implements the change, it must provide at least one year adequate time for affected operators to purchase leak detection equipment, establish leak survey routes, develop recordkeeping systems for these surveys and hire additional personnel following adoption of the new leak survey equipment. The Iowa Utilities Board (IUB) commented that the proposed amendment appears responsive to NAPSR Resolution 2006-3, which called for the reinstatement of leak surveys that were not included when requirements for Type B gathering lines were adopted in Amendment 192- 102. The IUB further noted that the proposed amendment includes a second part that [[Page 12765]] was not in the NAPSR resolution. The language of the second part reads: ``and fix hazardous leaks that are discovered in accordance with Sec. 192.703(c).'' ``Fix'' is hardly usual regulatory language and has no specified definition or usage history in Part 192. The IUB and MichCon DTE Energy suggested that PHMSA use alternate language that removes a nonstandard term and an unnecessarily complicated rule reference by simply saying ``and promptly repair hazardous leaks that are discovered.'' The Northeast Gas Association suggested that PHMSA revise its proposal to require operators of Type B regulated gathering lines to apply leak survey methods in accordance with Sec. 192.723 which provides the leak survey requirements for low-stress pipelines with a MAOP of less than 20 percent specified minimum yield strength (SMYS). Response: As for the comment that PHMSA should wait until its congressionally mandated review of existing regulations for gas and hazardous liquid gathering lines is complete, the study required by Section 21 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act requires PHMSA to study and report to Congress on: (A) The sufficiency of existing Federal and state laws and regulations to ensure the safety of gas and hazardous liquid gathering lines; (B) The economic impacts, technical practicability and challenges of applying existing Federal regulations to gathering lines that are not currently subject to Federal regulation when compared to the public safety benefits; and (C) Subject to a risk-based assessment, the need to modify or revoke existing exemptions from Federal regulation for gas and hazardous liquid gathering lines. The need to include leakage surveys as a compliance activity was identified between the publications of the Supplemental Notice of Proposed Rule Making (SNPRM) titled: ``Pipeline Safety: Gas Gathering Line Definition: Alternative Definition for Onshore Lines and Proposed Safety Standards,'' published October 3, 2005; 70 FR 57536 [Docket No. RSPA-1998-4868; Notice 5], and the Final Rule of the same title published March 15, 2006; 71 FR 13289 [Docket No. PHMSA-1998-4868]. The inclusion of leakage surveys as a compliance action was not included in the Final Rule because it was beyond the scope of the SNPRM and the agency did not want to further delay the rulemaking. During its annual meeting in September 2006, NAPSR also passed a resolution [NAPSR Resolution 2006-3] requesting the regulatory change to Type B lines. As for the comment that Type B leaks due to excavation damage may pose a greater risk, the annual Type B report data for calendar year 2011 indicated that there were 289 leaks eliminated or repaired by operators of onshore Type B gathering lines, with the leading cause of leaks being external. Excavation damage is and has been recognized as a high risk for Type B gathering lines. This point was elaborated on in the Gas Gathering Line Definition in the SNPRM (October 3, 2005; 70 FR 57536) and Final Rule (March 15, 2006; 71 FR 13289), and served as the basis for the compliance activities for Type B lines (damage prevention programs, placement of line markers, and public awareness programs). This amendment will add one more recognized risk control activity required on Type B gathering lines. Regarding the comment that PHMSA should estimate the costs of compliance, PHMSA performed a cost analysis by averaging the daily rate of two leak survey service providers. The average cost of surveying two miles of pipeline per day equaled $600. The estimated that approximately 3,650 miles of Type B gathering lines will be required to be inspected annually at an average cost of $300 per mile for an upper bound annual cost of approximately $1.1 million. However, leak surveys, while not currently required for Type B gathering lines, are a widespread industry practice because they serve a business purpose in helping to detect leaks, thereby reducing lost gas and liability exposure. Although operators do not submit data on the extent of these surveys, PHMSA believes that approximately half of all Type B gathering line mileage that would otherwise be affected by this proposal is already being inspected. This is based on the fact that this is a widespread industry practice and until 2006, this was an existing regulatory requirement. Therefore, a more realistic estimate of the actual incremental cost is approximately 50% of the upper bound of $1.1 million, or $0.55 million per year. The Northeast Gas Association, in a comment on PHMSA's published NPRM, noted there were operational similarities between Type B gathering lines and gas distribution lines that operate at similar, lower pressures, and requested PHMSA apply leak survey standards to Type B gathering lines that were more in line with leak survey standards for distribution lines, rather than leak survey standards for transmission lines. Title 49 CFR 192.706 requires transmission line leak surveys at intervals not exceeding 15 months, but at least once each calendar year, and more frequently in densely populated areas. NAPSR believes that Type B gathering lines should be subject to the same requirements, as Type B gathering lines can carry gas that is corrosive, and gas leaks are a significant hazard on those low-stress pipelines. Therefore, requiring leak surveys on Type B gathering lines is an appropriate and necessary risk-management measure. NAPSR also noted in their comments that some Type B gathering lines are located under broad paved areas, where electrical surveys that detect pipe damage may be difficult to perform, and leaking gas can migrate under the pavement and accumulate in surrounding structures. NAPSR recommends that leak detection surveys should be required to ensure the safety of these lines. As it stands, distribution lines in business districts must be surveyed each calendar year, with the remainder of distribution lines subject to leak survey at frequencies driven by local conditions but at an interval that does not exceed 5 years. Distribution lines, per the regulations, are required to be odorized which provides members of the public with a warning system for the period between surveys. The gas in gathering lines is un-odorized, so the public does not have any advance warning of line leaks outside of those leak surveys. Leak surveys would serve as the warning bell. Regarding the concerns raised by commenters about the cost of this proposal, under the current regulations, Type B gathering lines are treated the same as transmission lines for design, installation, construction, and initial testing and inspection. If the line in question is composed of metal, the line must also comply with the same corrosion control requirements as transmission lines. Similar to transmission lines, Type B gathering lines must be included in damage prevention and public education programs, have established MAOPs under Sec. 192.619, and comply with the requirements for installing and maintaining line markers. Because Type B gathering lines are regulated with many of the same requirements as transmission lines, it would follow that Type B gathering lines and transmission lines have a similar risk profile. Therefore, because transmission lines are subject to annual leak surveys, Type B gathering lines [[Page 12766]] should be subject to the same requirement for safety reasons. While leak surveys are not currently required for Type B gathering lines, they are a widespread industry practice that help operators detect leaks early and avoid loss of lives, gas and liability exposure. When this voluntary practice becomes a regulation it will provide a standard and consistent level of safety to the American public and ensure the integrity of these lines. Taking this into consideration, as well as the GPAC's recommendation and the evaluation of public comments, PHMSA has adopted Sec. 192.9(d)(7) as proposed with the minor modification of substituting the word ``fix'' with ``repair.'' (3) Qualifying Plastic Pipe Joiners Sec. 192.285(c) Proposal: Section 192.285 contains requirements for qualifying persons to make joints in plastic pipe. Under Sec. 192.285(c), ``[a] person must be re-qualified under an applicable procedure, if during any 12-month period that person: (1) Does not make any joints under that procedure; or (2) has three joints or three percent of the joints made, whichever is greater under that procedure that are found unacceptable by testing under Sec. 192.513.'' In its petition to amend the regulations (2008-03-AC-1), NAPSR noted that the current rule, with its 12-month time period, requires detailed records of each individual joiner's activities and sets the stage for requalification date ``creep,'' where a joiner must requalify at an earlier date every year. NAPSR commented that the existing regulatory language sets a very low standard for joiner requalification and noted that the large number of operators requesting similar waivers demonstrates that a requalification system like the one proposed in its resolution is acceptable and preferred by pipeline operators. In the NPRM, based on the NAPSR petition, PHMSA proposed to revise Sec. 192.285 to provide greater scheduling flexibility and require requalification of a joiner if any production joint is found unacceptable. Comments: Center Point Energy (CPE) noted that it is overly excessive to disqualify and retrain a joiner if one joint is found unacceptable during a 12-month period CPE suggested that PHMSA leave Sec. 192.285(c)(2) as written and that quality assurance/quality checks of potentially unacceptable joints be accomplished through Sec. 192.513 testing. CPE also queried whether PHMSA has data from a study to show that an individual who makes one unacceptable joint will make more. City Utilities of Springfield, Missouri, suggested that we amend the language to clarify that requalification is necessary only if the joint failure is due to operator error. Nicor Gas (Nicor), while supporting the proposal to add a three- month grace period in the requalification interval, does not support the proposed revision that would require requalification of the joiner if one joint is found unacceptable by the required pressure testing. Nicor commented that the proposal is unnecessarily restrictive and not validated or supported by documentation from NAPSR. Nicor noted that there are field conditions and/or circumstances beyond the joiner's control (rain, snow, blowing dirt, trench cave-ins, equipment malfunctions and material flaws) that would affect the joining process without reflecting a lack of skill or proper training. All these incidents may lead to an unacceptable joint. TPA also disagrees with the proposal to impose a zero-failure tolerance standard for plastic pipe joiners and commented that perfection in the performance of any task in any industry 100 percent of the time is rarely, if ever, achieved. TPA commented on the contrast of the regulations in plastic joining versus welding of steel pipelines and noted that the existing regulations for welders do not impose a zero-tolerance standard, even though most steel pipelines operate at higher pressures than plastic pipelines, and would pose a higher safety risk to the public. The zero tolerance proposal for plastic pipe joiners also fails to consider that all plastic pipe is required to be pressure tested before going into service and that this testing provides an additional layer of safety assurance that plastic pipe joints are safe before pipeline operation begins. AGA suggested that PHMSA analyze data on fusion failures, present the information to the public and then determine how best to address the issue. AGA further commented that the amendment to prohibit the entire crew from further fusion after one joint failure until requalification occurs seems unnecessarily severe, is unsupported by statistical evidence and has the potential to create unexpected adverse consequences. Response: PHMSA reviewed the comments received on the topic including those that raised concerns of, and requested clarification on, the changes surrounding requalification if one joint is found unacceptable. PHMSA understands some of the concerns may have been related to the language used in the preamble and additional clarification may be needed regarding PHMSA's intent. PHMSA does not believe the proposed requirements are as onerous as some of the commenters indicated, nor would there necessarily be a zero tolerance policy in effect as a result of the proposed changes. PHMSA agrees there could be a number of factors including some beyond the joiners control such as weather, equipment malfunctions and material flaws, which could result in an unacceptable joint. However, PHMSA expects some evaluation would be done following any unacceptable joint, and in some cases evaluation may be necessary on a case-by-case basis. If an unacceptable joint is a result of a factor(s) clearly beyond the joiner's control, PHMSA does not expect those conditions to affect the requalification of the joiner. Likewise, if an individual fusing a joint realizes that it is a bad joint, cuts it out, and fuses another (acceptable) joint immediately following, PHMSA does not expect that the joiner would have to requalify. On the other hand, if an unacceptable joint is related to issues that are within the joiner's control, that joiner would need to be re-qualified. While PHMSA has presented some general expectations, ultimate determination of the adequacy of an acceptable joint, whether or not the joiner would need to be requalify, and what may constitute an adequate qualifying joining test would be up to which ever entity inspects the joint. In most cases, particularly for intrastate systems, it would be up to the individual state. In response to the comments regarding the burden of this provision, PHMSA notes that the changes may help reduce some of the current burden associated with the paperwork, tracking and record-keeping requirements that were associated with ``three joints or three percent of the joints made, whichever is greater'' in the current regulatory language. Regarding the comments inquiring about data or other studies surrounding joints, PHMSA is not aware of any studies showing that an individual who makes one unacceptable joint will make more. On the other hand, PHMSA is not aware of any data or studies that can guarantee that an individual who makes one unacceptable joint won't make another unacceptable joint. The potential safety issues surrounding an unacceptable joint those are not addressed through proper evaluation and requalification seem to outweigh any benefit with continuing the qualification requirements as they currently exist in [[Page 12767]] the regulations. Many of these and other aspects were discussed with the GPAC, the transcripts of which are available in the docket. Following some discussion, the GPAC unanimously supported PHMSA's proposal that was based on the NAPSR petition. The PACs, industry and the public indicated that the original language in the regulations required numerous letters of interpretation and caused problems in the application of the regulations. The proposed language is also in keeping with some state waivers granted by PHMSA. Accordingly, the Final Rule revises Sec. 192.285 to provide greater scheduling flexibility and require requalification of a joiner if any production joint is found unacceptable. (4) Mill Hydrostatic Tests for Pipe To Operate at Alternative Maximum Allowable Operation Pressure Sec. 192.112 Proposal: Section 192.112 applies to pipe that will operate at the higher stresses allowed under the alternative MAOP permitted under Sec. 192.620 and specifies additional design requirements. In the NPRM, PHMSA proposed to revise Sec. 192.112(e) by eliminating the allowance for combining loading stresses imposed by pipe mill hydrostatic testing equipment for the mill test. Eliminating the allowance to combine equipment loading stresses will have the effect of increasing the internal test pressure for mill hydrostatic tests for new pipe to be operated at an alternative MAOP. This design requirement, combined with pipe mill dimensional checks for expansion, will help assure that all new pipes to be operated at an alternative MAOP receive an adequate mill test and have adequate strength. Comments: Evraz, a steel and pipe manufacturer, noted that eliminating the allowance for combining loading stresses imposed by pipe mill hydrostatic testing equipment could put mills that use testing processes that apply high end loadings at a competitive disadvantage to mills that do not. The amount of end loading applied depends on the testing process and equipment used. Mills that apply higher end loadings will produce combined stresses in excess of 100 percent SMYS if required to achieve 95 percent of SMYS based on gauge pressure alone. Evraz noted that the more effective way of addressing the potential of low strength line pipe would be to fully institute the changes in the 3rd addendum of the 44th edition of the American Petroleum Institute's (API), API Specification 5L, ``Specification for Line Pipe,'' (API Spec 5L). TransCanada Corporation suggested that PHMSA consult with pipe manufacturers regarding the potential impacts of consideration of end loading in the calculations of mill hydrostatic tests before adopting changes to the procedure. TransCanada maintained that the increased safety factor was already added in the 2008 Final Rule titled: ``Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines'' (73 FR 62148). Response: Pipe mill hydrostatic testing is a factory proof test used to ensure that new pipe has no structural or manufacturing flaws and adequate strength. Section 192.112 applies to pipe that will operate at the higher stresses allowed under the alternative MAOP rule. The mill test pressure of a minimum of 95 percent SMYS is being required to ensure that lower strength pipe is not used for alternative MAOP pipelines. The alternative MAOP rule allows pipelines to operate at stresses of up to 80 percent of SMYS, where other pipelines can only operate up to 72 percent SMYS. Pipelines that do not operate in accordance with the alternative MAOP must be mill tested as defined in the appropriate pipe manufacturing standard and the current edition of API Spec 5L incorporated by reference in Sec. 192.7 (b)(7). The 45th edition of API Spec 5L was incorporated by reference on January 5, 2015 (80 FR 168). API Spec 5L offers a lower requirement than that of a mill test of 95 percent SMYS in Sec. 192.112(e)(1) for non-alternative MAOP pipelines. During the 2008 through 2010 construction seasons, PHMSA identified a number of cases where new pipe did not meet regulatory specified strength requirements. Pipe that is 15 percent below the mandated SMYS was found on several new pipeline construction projects. On May 21, 2009, PHMSA issued an advisory bulletin (ADB-09-01) Docket No. PHMSA- 2009-0148--``Pipeline Safety: Potential Low and Variable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line Pipe''), alerting pipeline operators of issues found with low strength pipe. Eliminating the mill test allowance to combine equipment loading stresses will have the effect of increasing the internal test pressure for mill hydrostatic tests for new pipe to be operated at an alternative MAOP. When combined with pipe mill dimensional checks for expansion, that change will help assure that all new pipes for this service receive an adequate mill test and have adequate strength. This mill hydrostatic test criteria change will help to eliminate low strength pipe in alternative MAOP pipelines. During 2009 to 2010, INGAA conducted two studies/white papers titled, ``Guidelines for Evaluation and Mitigation of Expanded Pipes'' dated June 9, 2010, and ``Identification of Pipe with Low and Variable Mechanical Properties in High Strength, Low Alloy Steels'' dated September, 2009 (Docket No. PHMSA-2010-0026). The INGAA studies confirm that if the mill hydrostatic pressure test produced a stress of 95 percent or more of SMYS, and diameter dimensions were taken at intervals along the length of each joint in addition to the required end dimension measurements, expansion of the pipe beyond the set tolerances in the pipe specification did not occur. If unacceptable expansion has occurred, those pipe joints can be identified and eliminated. Since steel and pipe production are worldwide manufacturing processes, it is very difficult to determine that a standard quality assurance process has been fully implemented. Mill hydrostatic tests are the final quality assurance process in the pipe manufacturing chain. They are conducted by the pipe manufacturer and have the full quality assurance review of the pipe manufacturer and pipe purchaser/ pipeline operator. This new requirement is based upon an INGAA sponsored industry review of pipe making practices. If pipe is not tested to a higher pressure in the mill then the low strength pipe will create operational concerns in the field. The adoption of this amendment should expose low strength pipe in operation. Thus, PHMSA has adopted Sec. 192.112(e) as proposed. (5) Regulating the Transportation of Ethanol by Pipeline Sec. 195.2 Proposal: In the NPRM, PHMSA proposed to modify its definition of ``hazardous liquid'' to include ethanol. This action was based in part on a policy statement published in the Federal Register on August 10, 2007; 72 FR 45002 (Docket Number: PHMSA-2007-28136) 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 as a result of several Federal energy policy initiatives, which would result in greater use of pipelines for transporting biofuels. 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 [[Page 12768]] materials constitute ``hazardous liquids for purposes of the pipeline safety laws and regulations.'' PHMSA went on to say that the agency was considering a possible modification to Sec. 195.2 to include ethanol and biofuels in the definition of hazardous liquid. PHMSA invited comments on that proposal and on other issues related to the transportation of biofuels by pipeline. Comments: Thomas Lael Services, L.P., suggested that the term ``ethanol'' and ``bio-diesel petroleum'' should be added to the definition of ``hazardous liquid.'' AOPL added that rather than having another Federal agency or a number of state agencies attempt to regulate the safety of pipeline transportation of ethanol, that denatured ethanol be defined as a ``hazardous liquid'' under Sec. 195.2, so that ethanol transported via pipeline is regulated consistently with other energy liquids by PHMSA under 49 CFR part 195. Response: After evaluating the comments on the proposal, PHMSA has adopted the amendment to add the term ``ethanol'' to the definition of ``hazardous liquids'' in Sec. 195.2. In this Final Rule PHMSA will not adopt the commenter's suggestion that we add ``bio-diesel petroleum'' to the definition because this request is outside of the scope of this rulemaking. However, PHMSA may address this issue in a future rulemaking. (6) Limitation of Indirect Costs in State Grants Sec. 198.13 Proposal: PHMSA reimburses the states for a portion of the costs accrued in administering their pipeline safety programs and Congress appropriates the funds used to make these reimbursements on a regular basis. The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act) removed a provision that imposed a 20 percent cap on indirect expenses allocated to the pipeline safety program grants. In the NPRM, PHMSA proposed to incorporate the 20 percent limitation on indirect expenses into the regulations governing grants to state pipeline safety programs. Comments: PHMSA received several comments opposed to this proposal. IUB and NAPSR objected to the proposal to limit the indirect cost rate that can be recovered through a state's pipeline safety grant to 20 percent. They both stated that the limit is arbitrary and capricious and may prevent the recovery of legitimate costs of state participation in the Federal/state pipeline safety program. IUB said the 20 percent limit is not mandated by law or by any referenced Federal grant guide material or requirement. IUB also noted that there was no clear rationale as to why PHMSA should impose a requirement by rule that Congress found unnecessary and removed from law when the PIPES Act was passed in 2006. IUB and NAPSR noted that different states have different methods of allocating costs within their budget and no basis was presented for punishing states that distribute a larger portion of their costs as indirect costs. NAPSR is concerned that states could artificially inflate indirect costs to receive a larger grant payment. PACs' members pointed out that the way in which states do their budgeting and accounting varies and some states do have indirect costs that exceed the 20 percent limit. However, because of the 20 percent required cost share, states do not present their costs that are above that threshold. Some state representatives noted that their indirect cost submissions are required to be approved first at the Federal level and are highly scrutinized to ensure no padding is done. In addition to that, to ensure compliance, PHMSA performs frequent audits of the state programs. Response: PHMSA has decided not to adopt the proposal into regulation. However, PHMSA will maintain the 20 percent indirect cost cap through language in our payment agreements with states. As part of its state program, PHMSA has payment agreements with each state. These agreements are binding and cap indirect costs at 20 percent. (7) Transportation of Pipe Sec. 192.65 Proposal: Section 192.65 states that if pipe is to be transported by railroad, it will be operated at a hoop stress of 20 percent or more of SMYS, and has a diameter-to-wall-thickness ratio of 70 to one or more; the pipe must be transported in accordance with API RP 5L1. An exception is provided for certain pipe transported before November 12, 1970. That exception allows operators to use pipe stockpiled prior to the effective date of the original pipeline safety regulations, the transportation of which cannot be verified under API standards. Based on an NTSB investigation and recommendation resulting from an Enbridge pipeline incident that took place on July 4, 2002, near Cohasset, Minnesota, PHMSA proposed to revise the regulation to require that the rail transportation of all pipe be subject to the referenced API standards. Comments: We received several comments, including one from the NTSB in support of the proposal. The Committee on Pipe and Tube Imports (CPTI) Ad Hoc Large Diameter Line Pipe Producers Group agreed that the proposal would not have an adverse impact on operations or the ability to manufacture products. El Paso Pipeline Group (EPPG) commented that if PHMSA promulgates this amendment, it should specify that the use restriction does not apply to any pipe already installed, or to any pipe transported after Sec. 192.65 initially took effect. EPPG commented that the proposed wording may result in misinterpretation and unintended consequences, such as assuming that ``use'' applies to pipe currently installed rather than to pipe in stock, and that shipping records must be provided for all pipe exceeding the specified diameter- to-wall thickness ratio. EPPG proposed this rewording of the regulatory language: (a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not install pipe shipped by rail prior to November 12, 1970, unless the operator can show that the transportation was performed in a manner that meets the requirements of API RP 5L1. NAPSR agrees that any remaining stock of such pipe is likely to be minimal. Response: Surveys conducted by INGAA failed to find any vintage pipe covered by Sec. 192.65(a)(2). Therefore, PHMSA has no reason to continue the exemption and is removing this exemption from the regulation and adopting the amendment with one minor change. PHMSA is replacing the phrase ``operator may not use pipe'' with the phrase ``operator may not install pipe'' to clearly indicate that this amendment does not apply to pipe already installed. (8) Threading Copper Pipe: Sec. 192.279 Proposal: Section 192.279 specifies when copper pipe may be threaded and refers to Table C1 of American Society of Mechanical Engineers (ASME) Standard ASME/ANSI B16.5. In a letter dated June 11, 2009, the Gas Piping Technology Committee (GPTC) advised PHMSA that Table C1 was deleted in the most recent version of the ASME/ANSI B16.5, which is incorporated into Part 192 by reference. The GPTC stated that the information in Table C1 was taken from a different standard and that ASME/ANSI B36.10M, ``Standard for Welded and Seamless Wrought Steel Pipe,'' should be substituted as a more appropriate reference. PHMSA proposed to use ``threaded copper pipe if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe as listed in Table 1 of ASME B36.10M, Standard for Welded and Seamless Wrought Steel Pipe.'' [[Page 12769]] Comments: We received no public or PAC comments on this proposal. Response: PHMSA is unable to incorporate ASME/ANSI B36.10M, ``Standard for Welded and Seamless Wrought Steel Pipe'' due to the standards availability requirement described in Section 24 of the ``Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011'' (Pub. L. 112-90, January 3, 2012). Section 24 added a new public availability requirement for documents incorporated by reference after January 3, 2013. The law stated that beginning 1 year after the date of enactment of this subsection, the Secretary may not issue guidance or a regulation pursuant to this chapter that incorporates by reference any documents or portions thereof unless the documents or portions thereof are made available to the public, free of charge, on an Internet Web site. This section was further amended on August 9, 2013. The current law continues to prohibit the Secretary from issuing a regulation that incorporates by reference any document unless that document is available to the public, free of charge, but removes the Internet Web site requirements (Pub. L. 113-30, August 9, 2013). PHMSA will address this proposal in a future rulemaking action. (9) Offshore Pipeline Condition Reports Sec. Sec. 191.27 and 195.57 Proposal: In the NPRM, PHMSA proposed to remove Sec. Sec. 191.27 and 195.57. Sections 191.27 and 195.57 require operators to submit a report to PHMSA within 60 days of completing the underwater inspections of pipelines in the Gulf of Mexico required by Sec. Sec. 192.612(a), and 195.413(a). Sections 192.612(a) and 195.413(a) no longer require operators to perform an underwater inspection of all pipelines in the Gulf and its inlets. (See also Pub. L. 102-508 (Oct. 24, 1992) (modifying the statutory mandate for underwater inspection, reporting and reburial of pipelines in the Gulf and its inlets). Rather, those regulations call for periodic, risk-based inspections of shallow-water pipelines. The filing of a written report within 60 days of completing all of those inspections is not consistent with such an action. Additionally, sections 192.612(c) and 195.413(c) require operators to file their electronic/telephonic reports with the National Response Center within 24 hours of discovering that a pipeline in those areas is exposed or a hazard to navigation, which is sufficient to meet PHMSA's current information collection needs. Comments: PHMSA received no public comments on this proposal. Response: PHMSA has adopted the proposal to repeal Sec. Sec. 191.27 and 195.57. (10) Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies Sec. 195.452(h)(4)(i) Proposal: Section 195.452(h)(4)(i) specifies the actions that an operator of a hazardous liquid pipeline must take after discovering an immediate repair condition. One of those actions is a temporary reduction in operating pressure as determined under the formula provided in section 451.6.2.2 (b) of ASME/ANSI B31.4, ``Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids.'' The particular focus of that pressure reduction formula is corrosion. However, corrosion is only one of the threats that could cause an immediate repair condition under Sec. 195.452(h)(4)(i). In a July 17, 2007, Final Rule (72 FR 39017), PHMSA sought to modify Sec. 195.452(h)(4)(i) to provide for alternative methods of calculating a pressure reduction for immediate repair conditions caused by threats other than corrosion. The Office of the Federal Register was unable to incorporate that change due to inaccurate amendatory instructions. In the NPRM, PHMSA again proposed to revise Sec. 195.452(h)(4)(i) to make the same change as published in the July 17, 2007, Final Rule, with corrected amendatory instructions. Comments: In response to our proposal, the TransCanada Corporation commented that it acknowledges the limitations of the current language in Sec. 195.452(h)(4)(i) and believes a revision to the language in this section is appropriate. However, since Sec. 195.452(h)(4)(i)(B) provides for the calculation of the remaining strength using methods that include, ``but are not limited to,'' ASME/ANSI B31G, ``Manual for Determining the Remaining Strength of Corroded Pipelines,'' (ASME/ANSI B31G) or AGA Pipeline Research Committee, Project PR-3-805, ``A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,'' (PR-3-805 (RSTRING)), they do not believe a reference to the design requirements of Sec. 195.106 is necessary. TransCanada commented that the ability to use alternative methods for calculating a pressure reduction would be incorporated with only a reference to Sec. 195.452(h)(4)(i)(B). They suggested the following language in lieu of what PHMSA has proposed: Sec. 195.452(h)(4)(i): ``Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety an operator 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 criteria in paragraph (h)(4)(i)(B) of this section. If no suitable remaining strength calculation method can be identified, a minimum 20 percent or greater operating pressure reduction must be implemented until the anomaly is repaired. An operator must treat the following conditions as immediate repair conditions.'' The AOPL commented that the proposed language requiring the calculation of pressure reductions for detected anomalies should be modified to appropriately reference suitable calculation methods. API noted that Sec. 195.452(h)(4)(i)(B) already allows the use of PR-3-805 (RSTRENG), modified PR-3-805 (RSTRENG), or a suitable alternative remaining strength calculation method to be used, and therefore already fully covers the calculation of a temporary reduction in operating pressure. The API suggests that the following sentence in the proposed section is redundant: ``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.'' The LPAC suggested the following language: Sec. 195.452(h)(4)(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 referenced in paragraph (h)(4)(i)(B) of this section. If no suitable remaining strength calculation method can be identified, a minimum 20 percent or greater operating pressure reduction, based on actual operating pressure for two months prior to the date of inspection, must be implemented until the anomaly is repaired. An operator must treat the following conditions as immediate repair conditions: [. . .]'' Response: PHMSA believes both commenters were trying to make similar changes. In the Final Rule, PHMSA is adopting LPAC's suggested language as it best clarifies that an operator must calculate remaining strength or reduce operating pressure until a repair can be completed. [[Page 12770]] (11) Testing Components Other Than Pipe Installed in Low-Pressure Gas Pipelines Sec. Sec. 192.503 and 192.505 Proposal: In the NPRM, PHMSA proposed to amend Sec. Sec. 192.503 and 192.505 to exempt certain components from the strength test requirement in Subpart J of Part 192. This proposal was based on a petition from the GPTC in a letter dated March 25, 2010. The GPTC argued that the primary purpose of a post-installation strength test is to prove the integrity of the entire pipeline system. The GPTC further noted that the most important parts to check of a single-component replacement are the joints that connect the component to the pipeline, and that these joints are currently exempted from testing for all gas pipelines by paragraph (d) of Sec. 192.503. Comments: PHMSA received many comments in support of this proposal. We also received some comments asking that we expand the list and sources of standards that can be used to establish pressure ratings. One commenter asked that we review all referenced standards and provide exemptions for all standards that establish pressure ratings. Response: PHMSA is adopting the amendment as proposed. The request to expand the list and sources of standards that can be used to establish pressure ratings is out of the scope of this rulemaking, as is the request to review all referenced standards. Therefore, those requests have not been adopted but may be considered in future rulemaking actions. (12) Alternative MAOP Notifications Sec. 192.620(c)(1) Proposal: Section 192.620(c)(1) currently requires a pipeline operator to notify each PHMSA pipeline safety regional office where the pipeline is in service of its election to use an alternative MAOP pressure with respect to a segment at least 180 days before operating at the alternative pressure. An operator must also notify a state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state. PHMSA proposed to require that for new pipelines, an operator would notify the PHMSA pipeline safety regional office of planned alternative MAOP design and operations 180 days prior to start of pipe manufacturing or construction activities. An operator would also notify state pipeline safety authorities when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state. PHMSA also proposed to revise Sec. 192.620(c)(8) to correct a typographical error related to the reference to Sec. 192.611(a). The proposal to require 180 day notice for new pipelines was to allow sufficient time for PHMSA to conduct any needed material manufacturing and construction inspections, including checks of new pipe rolling and coating processes, visit the new pipeline field sites during construction, analyze operating history of existing pipelines, and review test records, plans, and procedures. Comments: INGAA suggested that the proposal should apply only prospectively, that the regulation should include an alternative notice period measured from the placement of the pipe purchasing order to the start of pipe manufacturing and that the language needs clarification with regard to new pipe. In its comments to the NPRM, INGAA noted that for new pipeline projects the application and permitting process can extend over months or years before approval to construct is granted. Once this approval is obtained, pipe orders are placed and production dates are established. The interval from the time the pipe is ordered until the start of production is sometimes less than 180 days making it impractical to provide the required notice as the proposed rule is currently worded. To address this INGAA recommends that the wording be changed to 180 days or 10 business days before the operator places a purchasing order for the pipe or the pipe starts being manufactured. Panhandle Energy (Panhandle) recommended that the wording addressing new pipelines be changed to: ``For new pipelines, notify the PHMSA pipeline safety regional office 180 days prior to the start of pipe manufacturing and/or construction activities, if practicable, but no more than 10 business days after the operator places an order for the pipe or executes the pipeline construction contract.'' TPA commented that if the operator wishes to utilize the existing pipe stock that satisfies the MAOP regulation requirement, the 180 day notice to the manufacturer would be impossible, and that the language should be revised to remove ``and/or'' to provide clear, unambiguous standards. Response: PHMSA evaluated the comments and believes the proposed 180 days notification is too restrictive. Notification to PHMSA of new alternative MAOP pipeline project activities at least 60 days prior to start of pipe manufacturing or construction activities should not delay operator project activities. PHMSA needs this time to schedule personnel for safety inspections at both the pipe and coating mills and at the construction site prior to the start of pipe construction activities. PHMSA will require a 60 day notice by the operator prior to the start of pipe manufacturing or construction activities of new alternative MAOP pipelines. (13) National Pipeline Mapping System Sec. Sec. 191.29, 195.61 Proposal: The National Pipeline Mapping System (NPMS) is a geospatial dataset that contains information about PHMSA-regulated gas transmission pipelines, hazardous liquid pipelines, and hazardous liquid low-stress gathering lines. The NPMS also contains data layers for all liquefied natural gas plants and a partial dataset of PHMSA- regulated breakout tanks. In the NPRM, PHMSA proposed to codify the statutory requirement for the submission of the NPMS data into Parts 191 and 195. An NPMS submission consists of geospatial data, attribute data and metadata, public contact information, and a transmittal letter. PHMSA also proposed to require operators to follow the submission guidelines and dates set forth in the July 31, 2008, advisory bulletin (73 FR 44800: Pipeline Safety; National Pipeline Mapping System). Gas transmission operators and liquefied natural gas (LNG) plant operators would make their NPMS submissions on or before March 15, representing their assets as of December 31 of the previous year. Hazardous liquid operators would make their NPMS submissions on or before June 15, representing their assets as of December 31 of the previous year. Comments: Oleska commented that, though they agree that the requirements should be added to Part 191, requiring operators to report to both NPMS and PHMSA is unduly burdensome and is not necessary. The TPA asked that PHMSA revise the language to clarify that this proposal only covers hazardous liquid trunklines and regulated rural hazardous liquid gathering pipelines as defined in the NPMS Operator Standards. TPA and Oleska noted that the operator ID for each operator is the same as it is for PHMSA, and that PHMSA should have the ability to get whatever information it needs directly from the NPMS without operators having to submit two sets of data. TPA and Oleska suggested that it would be better for PHMSA to get its data from the NPMS, because two sets of data increase the chance of discrepancies, [[Page 12771]] especially if changes are made between annual submissions. Response: In response to TPA's and Oleksa's concern about submitting the data twice, operators will continue to make only one NPMS submission following the guidelines in the NPMS Operator Standards Manual on the NPMS Web site (www.npms.phmsa.dot.gov). This Final Rule imposes no additional submission requirements. In response to the concern about the NPMS's and PHMSA's capability to process all the gas, LNG plant operator and liquid operator submissions received on or before March 15 and June 15, respectively, PHMSA encourages operators to make their submissions early beginning on January 1 of each year. In the Final Rule, PHMSA is adopting the amendment to the NPMS as proposed. (14) Welders vs. Welding Operators Sec. Sec. 192.225, 192.227, 192.229, 195.214, 195.222 Proposal: The welding provisions in Subpart E of Part 192 and Subpart D of Part 195 allow qualification of welders in accordance with API Standard 1104, ``Welding of the ASME Pipelines and Related Facilities,'' (API Std 1104), section 6 or ASME Boiler and Pressure Vessel Code., section IX: ``Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators,'' (ASME BPVC, section IX). In the NPRM, PHMSA proposed to add references to additional qualification standards in API Std 1104, such as sections 12 and 13 for welders and welding operators of mechanized and automated welding equipment. The addition of these qualification references was intended to follow current industry practice. These standards have specific processes to ensure that qualified personnel are used for welding processes whether they are performed by welders or welding operators. Comments: EPPG commented that the proposed language appears to not allow for the qualification of a welding operator whose welds are regularly being assessed per the criteria in API Std 1104, Appendix A, which is regarded as being equivalent to section 9. EPPG suggested a revision of the proposed language of Sec. 192.227(a) to read: ``under section 6, or section 9 or Appendix A, as applicable of API Std 1104 (incorporated by reference, see Sec. 192.7).'' [Proposed deletion indicated by strikeout; proposed addition in bold]. INGAA recommended that while PHMSA is amending the welding regulations, PHMSA should take the opportunity to formally incorporate by reference Appendix B to API Std 1104 for in-service (also known as ``live line'') welding. Oleska suggested that the language of the proposed revision would be clearer if we changed ``pipe and components'' to read ``pipe or components.'' Panhandle commented that the proposed language for Sec. 192.229(c)(1) contains an oversight related to this equivalence. The section says, in part: A welder or welding operator qualified under Sec. 192.227(a)-- (1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding six calendar months the welder or welding operator has had one weld tested and found acceptable under section 6 or section 9 of API Std 1104 (incorporated by reference, see Sec. 192.7). According to Panhandle, sections 6 and 9 of API Std 1104 relate to workmanship criteria only. The proposed language would appear to exclude qualification of a welding operator whose welds are regularly being assessed per the criteria in API Std 1104, Appendix A which is regarded as being equivalent to ASME BPVC, section IX. It is reasonable to allow qualification for a welding operator whose work has been acceptable under the Appendix A criteria. Panhandle therefore suggested that PHMSA modify the proposed language in the notice to read: A welder or welding operator qualified under Sec. 192.227(a) may not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under section 6, section 9 or Appendix A of API Std 1104, as applicable (incorporated by reference, see Sec. 192.7). Response: The Final Rule allows welds to be evaluated to API Std 1104, section 9 or Appendix A, and eliminates the requirement that the weld be first evaluated to section 9, before using Appendix A. Evaluating the welds first according to section 9 incurs unnecessary time and cost without any benefit. PHMSA re-evaluated its proposal to add additional references to qualification standards in API Std 1104. PHMSA finds that adding API Std 1104, section 13 (``Automatic Welding Without Filler Metal Additions'') is inconsistent with pipeline safety. API Std 1104, section 13 is not used on regulated pipelines and would be a major change in girth welding standards. Also, for practical purposes, there are no commercially used pipeline welding systems in the United States to which API Std 1104, section 13 can be applied. Not adopting API Std 1104, section 13, will prevent an operator from using a potentially less safe welding system without a PHMSA special permit review. INGAA suggested that PHMSA use the Final Rule as an opportunity to formally incorporate by reference Appendix B to API Std 1104 for in- service (``live line'') welding. Parts 192 and 195 currently require that all welding procedures be qualified to API Std 1104, section 5 or ASME BPVC, section IX, and that all welders be qualified to API Std 1104, section 6 or ASME BPVC, section IX. API Std 1104, Appendix B is only applicable to in-service welds on live or ``hot'' pipelines, with pressurized product in the pipe. The qualification requirements of Appendix B are optimized for in-service welds, and differ greatly from API Std 1104, sections 5 and 6 and ASME BPVC, section IX. Thus, adding API Std 1104, Appendix B to the Final Rule is a significant change that is outside the scope of this rule. We will consider this change for a future regulatory action. Based upon further review by PHMSA of Part 192, Appendix C, PHMSA decided that adding welding operators for Appendix C qualification in Sec. 192.227(b) would be inappropriate for the following reasons: (1) Qualification of welding operators can be, and is more appropriately performed to API Std 1104, section 12, instead of Appendix C; (2) Appendix C is primarily used for lower pressure, smaller diameter distribution lines, which are welded by welders, not welding operators; and (3) The language in Appendix C was written for qualification of welders, and may not be appropriate for qualification of welding operators. We agree with the comments that API 1104, Appendix A should be included as a qualification reference. When we proposed to add the relevant references to welding qualification standards to be consistent with industry practice, we intended to include the Appendix A reference, a widely accepted standard. Appendix A is now cited in the final regulations applicable to welding and welding operators. (15) Components Fabricated by Welding Sec. 192.153 Proposal: Pressure vessels can be found in meter stations, compressor stations and other pipeline facilities to facilitate the removal of liquids and other materials from the gas stream. These vessels are designed, fabricated [[Page 12772]] and tested in accordance with the requirements of ASME Boiler & Pressure Vessel Code, section VIII Rules for Construction of Pressure Vessels,'' as required by Sec. 192.153 and Sec. 192.165(b)(3), and the additional test requirements of Sec. 192.505(b). In the NPRM, PHMSA proposed that because the standard ASME pressure vessel test in ASME BPVC, section VIII, division 1 is 1.3 times MAOP, an operator must specify the correct test pressure when placing an order for an ASME vessel to ensure it is designed and tested to the requirements of 49 CFR part 192. Unless a vessel is specially ordered with a test pressure of 1.5 times MAOP as prescribed by the purchaser, the vessel will be tested in accordance with the standard test factor of 1.3. If the vessel is not tested to 1.5 times the MAOP, it cannot be used in a compressor or meter station, or other Class 3 or Class 4 locations. The failure to meet this requirement can potentially lead to exceeding the design parameters of the vessel during subsequent testing of the pipeline system. The pressure test requirements in ASME BPVC, section VIII were lowered from a test factor of 1.5 to 1.3 by an earlier edition. PHMSA proposed to add Sec. 192.153 to clearly specify the design and test requirements for pressure vessels in meter stations, compressor stations, and other locations that are tested to Class 3 requirements. Under the proposal, all ASME pressure vessels subject to Sec. 192.153 and Sec. 192.165(b)(3) would be designed and tested at a pressure that is 1.5 times the MAOP, in lieu of the standard ASME BPVC, section VIII test pressure of 1.3 times the MAOP. Additionally, PHMSA proposed to revise Sec. 192.165(b)(3) reference to this requirement. Comments: Kern River, INGAA and Northern Natural Gas maintained that this proposal is not a simple clarification but a change from the previous understanding and practice of both PHMSA and the operators. If the proposed regulation is applied retroactively, this change will place many facilities constructed after the change in the pressure test requirements in ASME BPVC, section VIII, as well as many facilities uprated under special permits, in violation of ASME BPVC, sections I and II. INGAA noted that these sections of Part 192 and the ASME BPVC revision history make it clear that the proposed rule will require a number of operators to make substantial and costly changes. Northern Natural Gas commented that retesting and replacing of these in-service components would be unnecessary, very expensive, and take several years to complete. INGAA noted that station piping often includes fabricated sections that are assembled at the construction site. Many of these sections, such as compressor bottles, coolers and inlet scrubbers and separators are tested and certified by their manufacturers. Requiring a second test at the construction site as proposed would depart sharply from common practice, add costs that are not justified by a safety benefit and potentially invalidate the manufacturers' compliance certificates. Kern River further commented that station piping is commonly tested in several segments and it is not common practice to include and retest ASME code vessels since they are certified by the manufacturers and retesting would require dewatering. INGAA advised PHMSA to adopt an alternate clarification that these components do not require testing beyond the ASME code. If PHMSA adopts the current recommendation, it should clarify that the amendment applies to components placed into service after the amendment's effective date. Response: PHMSA has incorporated by reference ASME BPVC for pressure vessels. The revised ASME BPVC, section VII, division 1 has changed pressure testing standards from 1.5 times MAOP to 1.3 times MAOP. This proposal is not a change to the current pressure testing requirements found in Part 192, but simply a clarification to ensure a clearer understanding of PHMSA's pressure testing requirements for certain ASME BPVC vessels located in compressor stations, meter stations and other Class 3 or Class 4 locations. The pressure testing requirements for pipelines in the PSR (which by definition includes pressure vessels, meter stations, compressor stations and other facilities used to transport gas as defined in Part 192 and ASME/ANSI B31.8) in Class 3 and 4 areas, as well as those facilities located in Class 1 and Class 2 which are explicitly required by Sec. 192.505(b), requires a pressure test equal to a minimum of 1.5 times the MAOP. The testing requirements of Sec. 192.505(b) have not been revised and state that in a Class 1 or Class 2 location, each compressor station regulator station, and measuring station, must be tested to at least Class 3 location test requirements. This clarification of code requirements are to ensure that Industry does not incorrectly use the newer ASME BPVC standard for pressure testing even though that was never the requirement. This clarification will not lead to additional cost measures, and therefore, PHMSA is adopting this amendment as proposed. (16) Odorization of Gas Transmission Lateral Lines Sec. 192.625 Proposal: Section 192.625 contains requirements for operators to odorize combustible gas in a transmission line in Class 3 or Class 4 locations ``so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.'' Certain exceptions are recognized by regulation, including for a lateral line, ``which transports gas to a distribution center, [if] at least 50 percent of the length of that line is in a Class 1 or Class 2 location.'' This section does not specify a clear method for calculating the length of a lateral line, and that has led to inconsistencies in applying the odorization requirement. In the NPRM, PHMSA proposed to amend Sec. 192.625(b)(3) to state that the length of a lateral line, for purposes of calculating whether at least 50 percent of the line is in a Class 1 or Class 2 location, be measured between the distribution center and the first upstream connection to the transmission line. Comments: Texas Oil and Gas Association commented, and API supported this comment, that PHMSA's attempt to better define which natural gas transmission lateral pipelines are subject to the odorization requirement may create the unintended consequence of adversely impacting industrial facility (refinery) operations and product quality in addition to increasing emissions. TransCanada Corporation noted that the proposed amendment's apparent distinction between lateral and transmission lines appears to lack logic, as it allows parts of a line originally considered to be a ``lateral'' line to change classification due to introduction of a branch. TransCanada further noted that the industry is not aware of, nor has PHMSA presented in the preamble, statistical evidence that this understanding of lateral has caused safety issues resulting from operators applying this definition to exempt certain lines from odorization with commensurate safety benefits. TransCanada submits that the definition of ``lateral'' most commonly used by the industry more than adequately serves the interest of public safety. It also noted that ``laterals are not distinct classification of lines; rather, `laterals' are described according to their function (e.g., transmission, distribution or gathering).'' INGAA had similar comments and suggested that PHMSA convene a public hearing or workshop to develop the fundamental regulatory changes needed to align its policy objectives with [[Page 12773]] common pipeline configurations. The natural gas industry considers lateral lines to be any lines that branch off other lines. Section 192.625 does not specify a clear method to calculate the length of a lateral line, and that has led to inconsistency in applying the odorization requirement. Even with the proposed language, there is confusion on the calculation. There is no evidence, of record or otherwise, suggesting that the industry's understanding of ``lateral'' has caused any safety issues. The American Chemical Council (ACC) commented that the use of gas odorants at certain facilities could affect some chemical manufacturing processes and the quality of some chemicals. While there are well- established safety benefits of odorants in natural gas transmission that are fully consistent with the ACC member company interests in enhanced natural gas production and use, the ACC is concerned that the potential requirement to odorize lateral lines that carry natural gas may affect some industrial facilities. Further, the proposal could force chemical manufacturers to remove the odorant before processing, leading to a substantial potential increase in the effective cost of natural gas and in the cost of production. TPA commented that this change could also result in odorization equipment, including odorant storage tanks, being located in close proximity to populated areas, increasing the likelihood of false reports and odor complaints from nearby residents. According to TPA, some products manufactured with natural gas can be tainted by sulfur based odorant making the product worthless. Response: This controversial topic was discussed at length at the advisory committee meeting. GPAC members found it difficult to agree on how to calculate the 50 percent length of a lateral line between the distribution center and the first upstream connection to the transmission line. Committee members were also concerned with the costs and benefits of this proposal. GPAC voted unanimously for PHMSA not to adopt this proposal. Although PHMSA believes that proper odorization is important, this proposal requires further analysis. Therefore, PHMSA will re-evaluate the proposal and may consider the revision in a future rulemaking action. (17) Editorial Amendments A: Editorial Amendments Proposed in the NPRM In the NPRM, PHMSA proposed several editorial amendments to the regulations. (1) In Sec. 195.571, we proposed to revise the reference to NACE SP0169 to specify compliance with one or more of the applicable criteria contained in paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3. (2) In Sec. 195.2, we proposed to amend the definition of ``Alarm'' to correct an error in the codification of the new control room management regulations (74 FR 63310). (3) In Sec. Sec. 192.925(b) and (b)(2), we proposed to replace ``indirect examination'' with ``indirect inspection'' to maintain consistency with Sec. 192.925(a) and the applicable NACE standard. (4) In Sec. 195.428(c), we proposed to replace ``sections 5.1.2'' with ``section 7.1.2'' to correctly reference the overfill protection requirements for aboveground breakout tanks in the API Std 2510. (5) In section 192.3 we proposed to add the definition of ``Welder'' and ``Welding Operator. (6) In Sec. 195.2, we proposed to revise the definitions of ``alarm'' and ``hazardous liquid.'' None of these editorial amendments received any comment and, as such, we are adopting them all as proposed. B. Editorial Amendments Not Proposed in the NPRM Several administrative regulatory changes summarized in the following paragraphs are included in this Final Rule. Hazardous Liquid Construction Notifications 195.64 (c)(1)(i) PHMSA discovered an error in the hazardous liquid regulations covering operator notifications of planned construction, and gave notice of its intention to correct the regulatory language (see March 21, 2012; 77 FR 16472, Advisory Bulletin ADB-2012-04). Section 195.64(c)(1)(iii) requires notification for construction of a new pipeline facility but does not specify a minimum dollar threshold for the construction project. Section 195.64(c)(1)(i) also requires notification for construction of a new pipeline facility, but only for those projects with a cost of ten million dollars ($10,000,000) or more. PHMSA does not wish to be notified about hazardous liquid pipeline facility construction with a cost of less than ten million dollars, so Sec. 195.64(c)(1)(iii) is being deleted. Reporting and Notification Methods The NPRM proposed to remove the requirement to file offshore pipeline condition reports currently found in Sec. Sec. 191.27 and 195.57. This Final Rule completes the removal and changes Sec. Sec. 191.7 and 195.58 by removing the reference to offshore pipeline condition reports. Sections 191.25 and 195.56 include the method for submitting safety-related condition reports. Since the receipt and processing of these reports is extremely time sensitive, the regulations currently require submittal by facsimile and do not provide an option for electronically mailing the report to PHMSA. These amendments are non- substantive and allow operators easier reporting methods. In this Final Rule, these regulations are revised to allow submittal of reports by electronic mail. The remaining changes apply to the submittal methods for integrity management and operator qualification program notifications. Under changes made in this Final Rule, these notifications may now be submitted by either electronic mail or regular mail. For integrity management, changes are made in Sec. Sec. 192.949 and 195.452. For operator qualification programs, changes are made in Sec. Sec. 192.805 and 195.505. Regulatory Analyses and Notices Executive Order 12866, Executive Order 13563, and DOT Regulatory Policies and Procedures This Final Rule is a non-significant regulatory action under section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was not reviewed by the Office of Management and Budget. This Final Rule is not significant under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034). 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.'' PHMSA amended miscellaneous provisions to clarify and eliminate unduly burdensome requirements. PHMSA also responded to requests from industry and state pipeline safety representatives to revise its regulations. PHMSA anticipates that a majority of the amendments contained in this Final Rule will have economic benefits to the regulated community by [[Page 12774]] increasing the clarity of its regulations and reducing compliance costs. For example, the changes related to NPMS and ethanol are simply a regulatory codification of current requirements. The elimination of the exception in Sec. 192.65 related to the transportation of pipe should have minimal impact because the amount of pipe that would be eligible for the exception is very small. The elimination of the offshore pipeline condition report will eliminate a reporting requirement that is no longer necessary. Several provisions of the Final Rule are specifically designed to eliminate confusion and potentially lower costs for regulated entities. For example, the final addition of Sec. 192.153(e) is designed to prevent regulated entities from purchasing pressure vessels that do not comply with Sec. 192.505(b), but that do comply with ASME BPVC, section VII, as required by Sec. 192.165(b)(3). The changes with respect to qualifying plastic pipe joiners will prevent re- qualification date ``creep'' and provide operators greater re- qualification flexibility and overall cost savings. Annual Compliance costs associated with this rulemaking are estimated to be $0.55 million, all of which are associated with requirement of leak Surveys for Type B gathering lines. PHMSA estimates approximately 3,650 miles of Type B gathering lines will be required to be inspected annually. PHMSA estimates that the average cost of inspection is $300 per mile, bringing the upper bound limit of the total annual expenditure to approximately $1.1 million. A more realistic estimate of the actual incremental cost is approximately 50% of the upper bound of $.55 million. By performing leak surveys annually, operators are more likely to detect leaks early, thereby avoiding costlier future repairs and reducing the amount of gas lost. There are also practical, operational benefits to conducting leak surveys, in the form of greater knowledge of the state of the pipeline, including potential third-party encroachments, soil erosion, or intrusion by vegetation. The lead cause of these leaks is external corrosion. Leak surveys are particularly important for low pressure gas gathering lines because these lines tend to leak rather than rupture and because their gas is non-odorized, making leaks more difficult to detect. In addition to the direct operational benefits, annual leak surveys will also reduce the environmental harm caused by lost gas (i.e., the greenhouse gas potential of methane released into the atmosphere). Operator leak reporting also gives PHMSA valuable information that can be used in trending analysis for the determination of problem materials or poor operating practices. These important benefits cannot be readily quantified, but PHMSA believes that they are substantial. In addition, eliminating these leak helps to ensure that leaked gas does not collect and lead a catastrophic explosion or other incident. Although fortunately there have been no serious incidents involving Type B gathering lines in the past several years, increased leak surveys would reduce the potential of a future incident. At an incremental cost of $0.55 million per year, requiring annual leak surveys would be a cost-effective safety intervention if it prevents even a single fatal incident over a 16 year period. A more thorough discussion of the subjects and the associated costs and benefits can be found in the Regulatory Impact Analysis, a copy of which has been placed in the Docket, PHMSA-2010-0026. Regulatory Flexibility Act Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions would have a significant economic impact on a substantial number of small entities. Description of the reasons that action by PHMSA was taken. PHMSA, pipeline operators and others have identified certain errors, inconsistencies, and deficiencies in the pipeline safety regulations concerning the following subjects: (1) Performance of post- construction inspections; (2) leak surveys of Type B onshore gas gathering lines; (3) the requirements for qualifying plastic pipe joiners; (4) the transportation of ethanol by pipeline; (5) the transportation of pipe; (6) the filing of offshore pipeline condition reports and (7) the calculation of pressure reductions for hazardous pipeline anomalies. PHMSA is addressing these issues in this Final Rule. Succinct statement of the objectives of, and legal basis, for the Final Rule. Under the pipeline safety laws, 49 U.S.C. 60101 et seq., the Secretary of Transportation must prescribe minimum safety standards for pipeline transportation and for pipeline facilities. The Secretary has delegated the authority of 49 CFR 1.53(a) to the PHMSA Administrator. The Final Rule would make changes in the regulations consistent with the protection of persons and property, while changing unduly burdensome or confusing requirements. Description of small entities to which the Final Rule will apply. In general, the Final Rule will apply to pipeline operators, some of which may qualify as a small business as defined in Section 601(3) of the Regulatory Flexibility Act. Some pipelines are operated by jurisdictions with a population of less than 50,000 people, and thus qualify as small governmental jurisdictions. Some portions of the rule apply to manufacturers of pipeline components, as well as the contractors constructing or repairing a pipeline. Many of these may qualify as a small business entity. Description of the projected reporting, recordkeeping, and other compliance requirements of the Final Rule, including an estimate of the classes of small entities that will be subject to the rule, and the type of professional skills necessary for preparation of the report or record. The Final Rule does not directly impose any reporting or recordkeeping requirements. However, the rule creates an obligation to perform leak surveys of Type B gathering lines. This sort of survey is currently required of transmission lines. Professional technicians will be needed to comply with this requirement, and the time required for compliance will vary greatly with each system, depending on the system's size. The remainder of the Final Rule does not impose any significant compliance, recordkeeping, or reporting requirements. However, it affects the timing and substance of one type of report that must be created and maintained under existing regulations. The Final Rule stipulates that operators notify PHMSA field offices 60 days prior to pipe manufacturing or construction activities on new alternative MAOP pipelines. The current regulations require operators to notify PHMSA 180 days in advance of operating a pipeline at a higher alternative MAOP. Because operators must currently provide PHMSA with a 180 day notice prior to operating at the alternative MAOP the Final Rule does not impose any additional reporting requirements. Identification, to the extent practicable, of all relevant Federal rules that may duplicate, overlap, or conflict with the Final Rule. PHMSA is unaware of any duplicative, overlapping, or conflicting Federal rules. Description of any significant alternatives to the Final Rule that accomplish the stated objectives of applicable statutes and that minimize any significant economic impact of the [[Page 12775]] Final Rule on small entities, including alternatives considered. PHMSA is unaware of any alternatives which would produce smaller economic impacts on small entities while at the same time meeting the objectives of the relevant statutes. Several provisions of the Final Rule are specifically designed to eliminate confusion and potentially lower costs for regulated entities. For example, the addition of 49 CFR 192.153(e) is designed to prevent regulated entities from purchasing pressure vessels that do not comply with Sec. 192.505(b), but that do comply with ASME BPVC section VII, as required by Sec. 192.165(b)(3). PHMSA believes that this Final Rule impacts a substantial number of small entities but that this impact will be negligible. The one requirement that may have a significant cost impact on small businesses is leak surveys for Type B gas gathering lines. PHMSA estimates that requiring leakage surveys on Type B gas gathering lines will necessitate an annual expenditure of approximately 0.55 million dollars. The costs are based on surveying two miles of pipeline per day at an approximate daily cost of $300 per mile and PHMSA's estimation that 50 percent of the mileage affected by this proposal already complies with the surveying. The daily costs are an average day rate provided by two providers of leak survey services. The Small Business Administration's North American Industry Classification System Code for gas transmission pipeline operators defines a small business as those operators that have annual revenue of less than 25.5 million dollars. It is PHMSA's opinion that very few gas gathering operators have revenues less than 25.5 million dollars per year. No other types of small entities, such as manufacturers, will see a significant cost impact. Therefore, this amendment will not affect a substantial number of small businesses. Based on the facts available about the expected impact of this rulemaking, I certify, under Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605) that this Final Rule will not have a significant economic impact on a substantial number of small entities. Executive Order 13175 PHMSA has analyzed this Final Rule according to the principles and criteria in Executive Order 13175, ``Consultation and Coordination with Indian Tribal Governments.'' Because this Final Rule does not significantly or uniquely affect the communities of the Indian tribal governments or impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply. Paperwork Reduction Act This Final Rule imposes no new requirements for recordkeeping and reporting. Unfunded Mandates Reform Act of 1995 This Final Rule does not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It would not result in costs of $100 million, adjusted for inflation, or more in any one year to either state, local, or tribal governments, in the aggregate, or to the private sector, and is the least burdensome alternative that achieves the objective of the Final Rule. National Environmental Policy Act The National Environmental Policy Act (42 U.S.C. 4321-4375) requires that Federal agencies analyze final actions to determine whether those actions will have a significant impact on the human environment. The Council on Environmental Quality regulations requires Federal agencies to conduct an environmental review considering (1) the need for the final action, (2) alternatives to the final action, (3) probable environmental impacts of the final action and alternatives, and (4) the agencies and persons consulted during the consideration process. 40 CFR 1508.9(b). 1. Purpose and Need PHMSA's mission is to protect people and the environment from the risks of hazardous materials transportation. The purpose of this rulemaking change is to improve compliance, provide clarification, address conflicting language and promote improved pipeline integrity and safety. In addition the purpose is to address small gaps in the current regulations and mitigate some of the negative externalities that can result from industry market failures. The need for this action stems from statutory requirements described in the Pipeline Safety, Regulatory Certainty, and job Creation Act of 2011 (Public Law 112-90), safety recommendations from the NTSB, and petitions from industry groups. In addition, due to shortfalls and unenforceability of industry standards, there arises a need for government to set minimum safety levels in pipeline regulations. PHMSA is making amendments and editorial changes to the regulations that includes modifying the requirements for: the performance of post- construction inspections, the conducting of leak surveys of Type B onshore gas gathering lines, qualifying plastic pipe joiners, the regulation of ethanol, the transportation of pipe, the filing of offshore pipeline condition reports, and the calculation of pressure reductions for hazardous liquid pipeline anomalies. 2. Alternatives In developing the Final Rule, PHMSA considered three alternatives: (1) No action. (2) Adopting all proposed amendments. (3) Adopting all proposed amendments except for leak surveys for Type Gas gathering lines. Alternative 1 PHMSA has an obligation to ensure the safe and effective transportation of hazardous liquids and gases by pipeline. The changes in this Final Rule serve that purpose by clarifying the regulations and eliminating unduly burdensome requirements. A failure to undertake these actions would allow for the continued imposition of unnecessary compliance costs without increasing public safety. Accordingly, PHMSA rejected the no action alternative. Alternative 2 PHMSA's Selected Action is a set of amendments and editorial changes to the Federal Pipeline Safety Regulations (49 CFR parts 191, 192, and 195). These revisions would eliminate inconsistencies and respond to several petitions for rulemaking and recommendations from our stakeholders, thereby facilitating the safe and effective transportation of hazardous liquids and gases by pipeline. The changes in this Final Rule will serve that purpose by clarifying certain regulatory requirements. Alternative 3 As discussed above under alternative 2, and in the published NPRM, PHMSA proposed to make certain amendments, corrections and editorial changes to the regulations. These revisions eliminate inconsistencies and respond to several petitions for rulemaking and recommendations from our stakeholders, thereby facilitating the safe and effective transportation of hazardous liquids and gases by pipeline. The proposal related to leak survey for Type B gas gathering lines. PHMSA established a new method for determining whether a gas pipeline is an ``onshore gathering line'' in 2006. PHMSA also imposed new safety standards for ``regulated onshore gathering lines,'' which divided regulated onshore gathering lines into [[Page 12776]] two risk-based categories. Type A gathering lines are metallic lines with a MAOP of 20 percent or more of SMYS, as well as nonmetallic lines with an MAOP of more than 125 psig, in a Class 2, 3, or 4 location. These lines are subject to all of the requirements in Part 192 that apply to transmission lines, except for the regulation that requires the accommodation of in-line inspection tools in the design and construction of certain new and replaced pipelines (49 CFR 192.150) and the integrity management requirements of Part 192, Subpart O. Operators of Type A gathering lines are also permitted to use an alternative process for demonstrating compliance with the requirements of Part 192, Subpart N, Qualification of Pipeline Personnel. Type B gathering lines includes metallic lines with a MAOP of less than 20 percent of SMYS, as well as nonmetallic lines with a MAOP of 125 psig or less, in a Class 2 location (as determined under one of three formulas) or in a Class 3 or Class 4 location. These lines are subject to less stringent requirements than Type A gathering lines. Specifically, any new or substantially changed Type B line must comply with the design, installation, construction, and initial testing and inspection requirements for transmission lines and, if of metallic construction, the corrosion control requirements for transmission lines. Operators must also include Type B gathering lines in their damage prevention and public education programs, establish the MAOP of those lines under Sec. 192.619, and comply with the requirements for maintaining and installing line markers that apply to transmission lines. It is important that dependable leak detection surveys are used to identify leakage so that appropriate repairs can be initiated to our nation's pipeline system. Prompt repair can help reduce the consequences of incidents to the public, environment and property. Performing field leak surveys is a preventative and proactive safety measure. Operator leak reporting also gives PHMSA valuable information that can be used in trending analysis for the determination of problematic materials or poor operating practices. Over time, unchecked leakage can potentially impact safety in addition to the fact that gas leaks have the risk of accidental ignition causing a fire or explosion. Prior to the 2006 Final Rule, operators had to perform leak surveys of non-rural gas gathering lines. Also, some Type B gathering lines are located under broad paved areas where electrical surveys (another means of detecting pipe damage) may be difficult to perform and leaking gas could migrate under the pavement and accumulate in surrounding structures. PHMSA believes that leak surveys are an effective means of ensuring the integrity of low-stress pipelines. Accordingly, PHMSA rejected this alternative. 3. Analysis of Environmental Impacts The Nation's pipelines are located throughout the United States in a variety of diverse environments--from offshore locations, to highly populated urban sites, to unpopulated rural areas. The pipeline infrastructure is a network of over 2.5 million miles of pipeline that move millions of gallons of hazardous liquids and over 55 billion cubic feet of natural gas daily. The biggest source of energy is petroleum, including oil and natural gas. Together, these commodities supply 65 percent of the energy in the United States. The physical environment potentially affected by the Final Rule includes airspace, water resources (e.g., oceans, streams, lakes), cultural and historical resources (e.g., properties listed on the National Register of Historic Places), biological and ecological resources (e.g., coastal zones, wetlands, plant and animal species and their habitat, forests, grasslands, offshore marine ecosystems) and special ecological resources (e.g., threatened and endangered plant and animal species and their habitat, national and state parklands, biological reserves, wild and scenic rivers) that exist directly adjacent to and within the vicinity of pipelines. Because the pipelines subject to the Final Rule contain hazardous materials, resources within the physically affected environment, as well as public health and safety, may be affected by gas pipeline incidents such as spills and leaks. Incidents on pipelines can result in fires and explosions, resulting in damage to the local environment. In addition, since pipelines often contain gas streams laden with condensates and natural gas liquids, failures also result in spills of these liquids, which can cause environmental harm. Depending on the size of a spill or gas leak and the nature of the impact zone, the environmental impacts could vary from property and environmental damage to injuries or, on rare occasions, fatalities. A majority of the amendments in this Final Rule are not substantive in nature and would have little or no impact on the human environment. It is likely that on a national scale, the cumulative environmental damage from pipelines is reduced, or at a minimum, unchanged. Requiring leakage surveys on Type B gathering lines will have positive environmental impacts. The Environmental Protection Agency (EPA) data indicate that methane contributed to nine percent of the reported greenhouse gas emissions in Calendar Year 2011 (www.epa.gov/methane/). Operators reported 289 leaks repaired on regulated Type B gathering lines in 2011. It is expected that with formalized leak survey programs in place, emissions will be further reduced, in addition to enhanced safety from leak repairs. Although beneficial, this would not be a large-scale impact on the environment. For these reasons, PHMSA has concluded that neither of the alternatives discussed above would result in any significant impacts on the environment. 4. Consultations Various industry associations and state regulatory agencies, such as the American Gas Association, the American Petroleum Associations and NAPSR, were consulted in the development of this rulemaking. 5. Finding of No Significant Impact PHMSA has determined that the selected alternative would not have a significant impact on the human environment. 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 published in the Federal Register on April 11, 2000, (70 FR 19477). Executive Order 13132 PHMSA has analyzed this Final Rule according to Executive Order 13132 (``Federalism''). The Final Rule does not have a substantial direct effect 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. This Final Rule does not impose substantial direct compliance costs on state and local governments. This Final Rule does not preempt state law for intrastate pipelines. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. Executive Order 13211 This Final Rule 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 supply, distribution, or energy use. [[Page 12777]] Further, the Office of Information and Regulatory Affairs has not designated this Final Rule as a significant energy action. List of Subjects 49 CFR Part 191 Pipeline Safety, Reporting, and recordkeeping requirements. 49 CFR Part 192 Fire prevention, Incorporation by reference, Pipeline safety, Security measures 49 CFR Part 195 Ammonia, Carbon dioxide, Incorporation by reference, Petroleum, Pipeline safety, Reporting and recordkeeping requirements. In consideration of the foregoing, 49 CFR Chapter I is amended as follows: PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS 0 1. The authority citation for Part 191 is revised to read as follows: Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, 60124, 60132, and 49 CFR 1.97. 0 2. In Sec. 191.7 paragraphs (a) and (b) are revised and paragraph (e) is added to read as follows: Sec. 191.7 Report submission requirements. (a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to the Pipeline and Hazardous Materials Safety Administration at http://portal.phmsa.dot.gov/pipeline unless an alternative reporting method is authorized in accordance with paragraph (d) of this section. (b) Exceptions: An operator is not required to submit a safety- related condition report (Sec. 191.25) electronically. * * * * * (e) National Pipeline Mapping System (NPMS). An operator must provide the NPMS data to the address identified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. 0 3. In Sec. 191.25 paragraph (a) is revised to read as follows: Sec. 191.25 Filing safety-related condition reports. (a) Each report of a safety-related condition under Sec. 191.23(a) must be filed (received by OPS within five working days, not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by electronic mail to [email protected] or by facsimile at (202) 366-7128. * * * * * Sec. 191.27 [Removed]. 0 4. Section 191.27 is removed. 0 5. Section 191.29 is added to read as follows: Sec. 191.29 National Pipeline Mapping System. (a) Each operator of a gas transmission pipeline or liquefied natural gas facility must provide the following geospatial data to PHMSA for that pipeline or facility: (1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. (2) The name of and address for the operator. (3) The name and contact information of a pipeline company employee, to be displayed on a public Web site, who will serve as a contact for questions from the general public about the operator's NPMS data. (b) The information required in paragraph (a) of this section must be submitted each year, on or before March 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, the operator must comply with the guidance provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 366-4595. PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS 0 6. The authority citation for Part 192 is revised to read as follows: Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, 60116 and 60118, 60137; and 49 CFR 1.97. 0 7. In Sec. 192.3, definitions for ``Welder'' and ``Welding operator'' are added in alphabetical order to read as follows: Sec. 192.3 Definitions. * * * * * Welder means a person who performs manual or semi-automatic welding. Welding operator means a person who operates machine or automatic welding equipment. 0 8. In Sec. 192.9, paragraph (d)(7) is added to read as follows: Sec. 192.9 What requirements apply to gathering lines? * * * * * (d) * * * (7) Conduct leakage surveys in accordance with Sec. 192.706 using leak detection equipment and promptly repair hazardous leaks that are discovered in accordance with Sec. 192.703(c). * * * * * 0 9. In Sec. 192.65, paragraph (a) is revised to read as follows: Sec. 192.65 Transportation of pipe. (a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not install pipe having an outer diameter to wall thickness of 70 to 1, or more, that is transported by railroad unless the transportation is performed by API RP 5L1 (incorporated by reference, see Sec. 192.7). * * * * * 0 10. In the table in Sec. 192.112, paragraph (e) is revised to read as follows: Sec. 192.112 Additional design requirements for steel pipe using alternative maximum allowable operating pressure. * * * * * [[Page 12778]] ------------------------------------------------------------------------ The pipeline segment must meet To address this design issue: these additional requirements: ------------------------------------------------------------------------ * * * * * * * ------------------------------------------------------------------------ (e) Mill hydrostatic test.......... (1) All pipe to be used in a new pipeline segment installed after October 1, 2015, must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. (2) Pipe in operation prior to December 22, 2008, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds. (3) Pipe in operation on or after December 22, 2008, but before October 1, 2015, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by ``ANSI/API Spec 5L'' (incorporated by reference, see Sec. 192.7). * * * * * * * ------------------------------------------------------------------------ 0 11. In Sec. 192.153, a new paragraph (e) is added to read as follows: Sec. 192.153 Components fabricated by welding. * * * * * (e) A component having a design pressure established in accordance with paragraph (a) or paragraph (b) of this section and subject to the strength testing requirements of Sec. 192.505(b) must be tested to at least 1.5 times the MAOP. 0 12. In Sec. 192.165, paragraph (b)(3) is revised to read as follows: Sec. 192.165 Compressor stations: Liquid removal. * * * * * (b) * * * (3) Be manufactured in accordance with section VIII ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see Sec. 192.7) and the additional requirements of Sec. 192.153(e) except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4, or less. 0 13. In Sec. 192.225, paragraph (a) is revised to read as follows: Sec. 192.225 Welding procedures. (a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12, or Appendix A of API Std 1104 (incorporated by reference, see Sec. 192.7) or section IX ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see Sec. 192.7), to produce welds which meet the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the referenced welding standard(s). * * * * * 0 14. Section 192.227 is revised to read as follows: Sec. 192.227 Qualification of welders and welding operators. (a) Except as provided in paragraph (b) of this section, each welder or welding operator must be qualified in accordance with section 6, section 12, or Appendix A of API Std 1104 (incorporated by reference, see Sec. 192.7), or section IX of ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see Sec. 192.7). However, a welder or welding operator qualified under an earlier edition than the edition listed in Sec. 192.7 may weld but may not re- qualify under that earlier edition. (b) A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C of this part. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test. 0 15. Section 192.229 is revised to read as follows: Sec. 192.229 Limitations on welders and welding operators. (a) No welder or welding operator whose qualification is based on nondestructive testing may weld compressor station pipe and components. (b) A welder or welding operator may not weld with a particular welding process unless, within the preceding 6 calendar months, the welder or welding operator was engaged in welding with that process. (c) A welder or welding operator qualified under Sec. 192.227(a)-- (1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under either section 6, section 9, section 12 or Appendix A of API Std 1104 (incorporated by reference, see Sec. 192.7). Alternatively, welders or welding operators may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 7\1/2\ months. A welder or welding operator qualified under an earlier edition of a standard listed in Sec. 192.7 of this part may weld, but may not re-qualify under that earlier edition; and, (2) May not weld on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS unless the welder or welding operator is tested in accordance with paragraph (c)(1) of this section or re-qualifies under paragraph (d)(1) or (d)(2) of this section. (d) A welder or welding operator qualified under Sec. 192.227(b) may not weld unless-- (1) Within the preceding 15 calendar months, but at least once each calendar year, the welder or welding operator has re-qualified under Sec. 192.227(b); or (2) Within the preceding 7\1/2\ calendar months, but at least twice each calendar year, the welder or welding operator has had-- (i) A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or (ii) For a welder who works only on service lines 2 inches (51 millimeters) or smaller in diameter, the welder has had two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part. 0 16. In Sec. 192.241, paragraph (c) is revised to read as follows: Sec. 192.241 Inspection and test of welds. * * * * * (c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by [[Page 12779]] reference, see Sec. 192.7). Appendix A of API Std 1104 may not be used to accept cracks. 0 17. In Sec. 192.243, paragraph (e) is revised to read as follows: Sec. 192.243 Nondestructive testing. * * * * * (e) Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder or welding operator's work for each day must be nondestructively tested, when nondestructive testing is required under Sec. 192.241(b). * * * * * 0 18. In Sec. 192.285, paragraph (c) is revised to read as follows: Sec. 192.285 Plastic pipe: Qualifying persons to make joints. * * * * * (c) A person must be re-qualified under an applicable procedure once each calendar year at intervals not exceeding 15 months, or after any production joint is found unacceptable by testing under Sec. 192.513. * * * * * 0 19. Section 192.305 is revised to read as follows: Sec. 192.305 Inspection: General. Each transmission line and main must be inspected to ensure that it is constructed in accordance with this subpart. An operator must not use operator personnel to perform a required inspection if the operator personnel performed the construction task requiring inspection. Nothing in this section prohibits the operator from inspecting construction tasks with operator personnel who are involved in other construction tasks. 0 20. In Sec. 192.503, a new paragraph (e) is added to read as follows: Sec. 192.503 General requirements. * * * * * (e) If a component other than pipe is the only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies that: (1) The component was tested to at least the pressure required for the pipeline to which it is being added; (2) The component was manufactured under a quality control system that ensures that each item manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or (3) The component carries a pressure rating established through applicable ASME/ANSI, Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS) specifications, or by unit strength calculations as described in Sec. 192.143. Sec. 192.505 [Amended] 0 21. In Sec. 192.505, paragraph (d) is removed and paragraph (e) is redesignated as paragraph (d). 0 22. In Sec. 192.620, paragraph (c)(1) and the first sentence of paragraph (c)(8) are revised to read as follows: Sec. 192.620 Alternative maximum operating pressure for certain steel pipelines. * * * * * (c) * * * (1) For pipelines already in service, notify the PHMSA pipeline safety regional office where the pipeline is in service of the intention to use the alternative pressure at least 180 days before operating at the alternative MAOP. For new pipelines, notify the PHMSA pipeline safety regional office of planned alternative MAOP design and operation at least 60 days prior to the earliest start date of either pipe manufacturing or construction activities. An operator must also notify the state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state. * * * * * (8) A Class 1 and Class 2 location can be upgraded one class due to class changes per Sec. 192.611(a). * * * * * * * * 0 23. In Sec. 192.805 paragraph (i) is revised to read as follows: Sec. 192.805 Qualification program. * * * * * (i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the administrator or state agency has verified that it complies with this section. Notifications to PHMSA may be submitted by electronic mail to [email protected], or by mail to ATTN: Information Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New Jersey Avenue SE., Washington, DC 20590. 0 24. In Sec. 192.925, the introductory text of paragraph (b) and the introductory text of paragraph (b)(2) are revised to read as follows: Sec. 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? * * * * * (b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI B31.8S (incorporated by reference, see Sec. 192.7), section 6.4, and in NACE SP0502 (incorporated by reference, see Sec. 192.7). An operator must develop and implement a direct assessment plan that has procedures addressing pre-assessment, indirect inspection, direct examination, and post assessment. If the ECDA detects pipeline coating damage, the operator must also integrate the data from the ECDA with other information from the data integration (Sec. 192.917(b)) to evaluate the covered segment for the threat of third party damage and to address the threat as required by Sec. 192.917(e)(1). * * * * * (2) Indirect inspection. In addition to the requirements in ASME/ ANSI B31.8S, section 6.4 and in NACE SP0502, section 4, the plan's procedures for indirect inspection of the ECDA regions must include-- * * * * * 0 25. Section 192.949 is revised to read as follows: Sec. 192.949 How does an operator notify PHMSA? An operator must provide any notification required by this subpart by-- (a) Sending the notification by electronic mail to [email protected]; or (b) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE., Washington, DC 20590. PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE 0 26. The authority citation for Part 195 is revised to read as follows: Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60116, 60118, 60132, 60137, and 49 CFR 1.97. 0 27. In Sec. 195.2, the definitions of ``alarm'' and ``hazardous liquid'' are revised and definitions for ``welder'' and ``welder operator'' are added in appropriate alphabetical order to read as follows: Sec. 195.2 Definitions. * * * * * [[Page 12780]] Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters. * * * * * Hazardous liquid means petroleum, petroleum products, anhydrous ammonia, or ethanol. * * * * * Welder means a person who performs manual or semi-automatic welding. Welding operator means a person who operates machine or automatic welding equipment. 0 28. In Sec. 195.56 paragraph (a) is revised to read as follows: Sec. 195.56 Filing safety-related condition reports. (a) Each report of a safety-related condition under Sec. 195.55(a) must be filed (received by OPS) within five working days (not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by electronic mail to [email protected], or by facsimile at (202) 366-7128. * * * * * Sec. 195.57 [Removed] 0 29. Section 195.57 is removed. 0 30. In Sec. 195.58, paragraphs (a) and (b) are revised and a new paragraph (e) is added to read as follows: Sec. 195.58 Report submission requirements. (a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to PHMSA at http://opsweb.phmsa.dot.gov unless an alternative reporting method is authorized in accordance with paragraph (d) of this section. (b) Exceptions: An operator is not required to submit a safety- related condition report (Sec. 195.56) electronically. * * * * * (e) National Pipeline Mapping System (NPMS). An operator must provide NPMS data to the address identified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. 0 31. Section 195.61 is added to read as follows: Sec. 195.61 National Pipeline Mapping System. (a) Each operator of a hazardous liquid pipeline facility must provide the following geospatial data to PHMSA for that facility: (1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. (2) The name of and address for the operator. (3) The name and contact information of a pipeline company employee, to be displayed on a public Web site, who will serve as a contact for questions from the general public about the operator's NPMS data. (b) This information must be submitted each year, on or before June 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, the operator must refer to the information provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 366-4595. Sec. 195.64 [Removed] 0 32. In Sec. 195.64, paragraph (c)(1)(iii) is removed. 0 33. Section 195.204 is revised to read as follows: Sec. 195.204 Inspection--general. Inspection must be provided to ensure that the installation of pipe or pipeline systems is in accordance with the requirements of this subpart. Any operator personnel used to perform the inspection must be trained and qualified in the phase of construction to be inspected. An operator must not use operator personnel to perform a required inspection if the operator personnel performed the construction task requiring inspection. Nothing in this section prohibits the operator from inspecting construction tasks with operator personnel who are involved in other construction tasks. 0 34. In Sec. 195.214, paragraph (a) is revised to read as follows: Sec. 195.214 Welding procedures. (a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12 or Appendix A of API Std 1104 (incorporated by reference, see Sec. 195.3), or section IX of ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see Sec. 195.3). The quality of the test welds used to qualify welding procedures must be determined by destructive testing. * * * * * 0 35. In Sec. 195.222 the heading, paragraph (a), the introductory text of paragraph (b), and paragraph (b)(2) are revised to read as follows: Sec. 195.222 Welders and welding operators: Qualification of welders and welding operators. (a) Each welder or welding operator must be qualified in accordance with section 6, section 12 or Appendix A of API Std 1104 (incorporated by reference, see Sec. 195.3), or section IX of ASME Boiler and Pressure Vessel Code (BPVC), (incorporated by reference, see Sec. 195.3), except that a welder or welding operator qualified under an earlier edition than an edition listed in Sec. 195.3, may weld but may not re-qualify under that earlier edition. (b) No welder or welding operator may weld with a welding process unless, within the preceding 6 calendar months, the welder or welding operator has-- * * * * * (2) Had one weld tested and found acceptable under section 9 or Appendix A of API Std 1104 (incorporated by reference, see Sec. 195.3). 0 36. In Sec. 195.228, paragraph (b) is revised to read as follows: Sec. 195.228 Welds and welding inspection: Standards of acceptability. * * * * * (b) The acceptability of a weld is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see Sec. 195.3). Appendix A of API Std 1104 may not be used to accept cracks. 0 37. In Sec. 195.234, paragraph (d) is revised to read as follows: Sec. 195.234 Welds: Nondestructive testing. * * * * * (d) During construction, at least 10 percent of the girth welds made by each welder and welding operator during each welding day must be nondestructively tested over the entire circumference of the weld. * * * * * 0 38. In Sec. 195.307 paragraphs (c) and (d) are revised to read as follows: [[Page 12781]] Sec. 195.307 Pressure testing aboveground breakout tanks. * * * * * (c) For aboveground breakout tanks built to API Std 650 (incorporated by reference, see Sec. 195.3) and first placed in service after October 2, 2000, testing must be in accordance with sections 7.3.5 and 7.3.6 of API Standard 650 (incorporated by reference, see Sec. 195.3). (d) For aboveground atmospheric pressure breakout tanks constructed of carbon and low alloy steel, welded or riveted, and non-refrigerated tanks built to API Std 650 or its predecessor Standard 12 C that are returned to service after October 2, 2000, the necessity for the hydrostatic testing of repair, alteration, and reconstruction is covered in section 12.3 of API Standard 653 (incorporated by reference, see Sec. 195.3). * * * * * 0 39. In Sec. 195.428, paragraph (c) is revised to read as follows: Sec. 195.428 Overpressure safety devices and overfill protection systems. * * * * * (c) Aboveground breakout tanks that are constructed or significantly altered according to API Std 2510 (incorporated by reference, see Sec. 195.3) after October 2, 2000, must have an overfill protection system installed according to API Std 2510, section 7.1.2. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API RP 2350 (incorporated by reference, see Sec. 195.3). However, an operator need not comply with any part of API RP 2350 for a particular breakout tank if the operator describes in the manual required by Sec. 195.402 why compliance with that part is not necessary for safety of the tank. * * * * * 0 40. In Sec. 195.452, paragraph (h)(4)(i) introductory text and paragraph (m) are revised to read as follows: Sec. 195.452 Pipeline integrity management in high consequence areas. * * * * * (h) * * * (4) * * * (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 referenced in paragraph (h)(4)(i)(B) of this section. If no suitable remaining strength calculation method can be identified, an operator must implement a minimum 20 percent or greater operating pressure reduction, based on actual operating pressure for two months prior to the date of inspection, until the anomaly is repaired. An operator must treat the following conditions as immediate repair conditions: * * * * * (m) How does an operator notify PHMSA? An operator must provide any notification required by this section by: (1) Sending the notification by electronic mail to [email protected]; or (2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave SE., Washington, DC 20590. 0 41. In Sec. 195.505 paragraph (i) is revised to read as follows: Sec. 195.505 Qualification program. * * * * * (i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the administrator or state agency has verified that it complies with this section. Notifications to PHMSA may be submitted by electronic mail to [email protected], or by mail to ATTN: Information Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New Jersey Avenue SE., Washington, DC 20590. 0 42. Section 195.571 is revised to read as follows: Sec. 195.571 What criteria must I use to determine the adequacy of cathodic protection? Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3 in NACE SP 0169 (incorporated by reference, see Sec. 195.3). Issued in Washington, DC, on February 26, 2015, under authority delegated in 49 CFR 1.97. Timothy P. Butters, Acting Administrator. [FR Doc. 2015-04440 Filed 3-10-15; 8:45 am] BILLING CODE 4910-60-P
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PART 1—INCOME TAXES (2) Description of how the hospital as a FAP-eligible individual and how
facility plans to address a significant that amount was determined and that
■ Paragraph 1. The authority citation health need. A hospital facility’s states, or describes how the individual
for part 1 continues to read in part as implementation strategy will have can get information regarding, the AGB
follows: described a plan to address a significant for the care.
Authority: 26 U.S.C. 7805 * * * health need identified through a CHNA * * * * *
for purposes of paragraph (c)(1)(i) of this
■ Par. 2. Section 1.501(r)–0 is amended section if the implementation strategy— PART 53—FOUNDATION AND SIMILAR
by revising the heading for the table of EXCISE TAXES
contents entry § 1.501(r)–7 to read as * * * * *
follows: ■ Par. 6. Section 1.501(r)–6 is amended
■ Par. 8. The authority citation for part
by:
§ 1.501(r)–0 Outlines of regulations. 53 continues to read in part as follows:
■ 1. Revising paragraph (c)(4)(i)(A).
* * * * * ■ 2. Revising the first sentence of Authority: 26 U.S.C. 7805 * * *
paragraph (c)(4)(iii)(A). ■ Par. 9. In § 53.4959–1(c), the
§ 1.501(r)–7 Effective/applicability date. ■ 3. Revising the second of paragraph paragraph heading is revised to read as
* * * * * (c)(4)(iv), Example 2. follows:
■ Par. 3. Section 1.501(r)–1 is amended ■ 4. Revising paragraph (c)(6)(i)(C)(1).
The revisions read as follows: § 53.4959–1 Taxes on failures by hospital
by revising the first sentence of
organizations to meet section 501(r)(3).
paragraph (b)(23) and revising § 1.501(r)–6 Billing and collection.
paragraph (b)(29)(ii)(B) to read as * * * * *
* * * * * (c) Effective/applicability date. * * *
follows:
(c) * * * * * * * *
§ 1.501(r)–1 Definitions. (4) * * *
* * * * * (i) * * * Martin V. Franks,
(A) Provides the individual with a Chief, Publications and Regulations Branch,
(b) * * *
(23) Partnership agreement means, for written notice that indicates financial Legal Processing Division, Associate Chief
purposes of paragraph (b)(22)(ii)(B) of assistance is available for eligible Counsel, (Procedure and Administration).
this section, all written agreements individuals, that identifies the ECA(s) [FR Doc. 2015–05519 Filed 3–10–15; 8:45 am]
among the partners, or between one or that the hospitality facility (or other BILLING CODE 4830–01–P
more partners and the partnership, and authorized party) intends to initiate to
concerning affairs of the partnership obtain payment for the care, and that
and responsibilities of the partners, states a deadline after which such DEPARTMENT OF TRANSPORTATION
whether or not embodied in a document ECA(s) may be initiated that is no earlier
referred to by the partners as the than 30 days after the date that the Pipeline and Hazardous Materials
partnership agreement. * * * written notice is provided. Safety Administration
* * * * * * * * * *
(iii) * * * 49 CFR Parts 191, 192, and 195
(29) * * *
(A) Otherwise meets the requirements
(ii) * * * [Docket No. PHMSA–2010–0026; Amdt. Nos.
of paragraph (c)(4)(i) of this section but,
(B) Without paying a fee to the 191–23; 192–120; 195–100]
instead of the notice described in
hospitality facility, hospital
paragraph (c)(4)(i)(A) of this section, RIN 2137–AE59
organization, or other entity maintaining
provides the individual with a FAP
the Web site; and Pipeline Safety: Miscellaneous
application form and a written notice
* * * * * indicating that financial assistance is Changes to Pipeline Safety
■ Par. 4. Section 1.501(r)–2 is amended available for eligible individuals and Regulations
by revising the second sentence of stating the deadline, if any, after which
paragraph (c) to read as follows: AGENCY: Pipeline and Hazardous
the hospital facility will no longer
Materials Safety Administration
accept and process a FAP application
§ 1.501(r)–2 Failures to satisfy section (PHMSA), Department of Transportation
501(r). submitted (or, if applicable, completed)
(DOT).
by the individual for the previously
* * * * * provided care at issue. * * * ACTION: Final rule.
(c) * * * For purposes of this
paragraph (c), a ‘‘willful’’ failure * * * * * SUMMARY: PHMSA is amending the
includes a failure due to gross (iv) * * * pipeline safety regulations to make
Example 2. * * * Y also makes numerous miscellaneous changes that update and
negligence, reckless disregard, or willful attempts to encourage G to apply for financial
neglect, and an ‘‘egregious’’ failure assistance, including by calling G to inform
clarify certain regulatory requirements.
includes only a very serious failure, her about the financial assistance available to These amendments address several
taking into account the severity of the eligible patients under Y’s FAP and to offer subject matter areas including the
impact and the number of affected assistance with the FAP application process. performance of post-construction
persons. * * * * * * inspections, leak surveys of Type B
* * * * * * * * * * onshore gas gathering lines, qualifying
■ Par. 5. Section 1.501(r)–3 is amended (6) * * * plastic pipe joiners, regulation of
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by revising the introductory text of (i) * * * ethanol, transportation of pipe, filing of
paragraph (c)(2) to read as follows: (C) * * * offshore pipeline condition reports, and
(1) If the individual is determined to calculation of pressure reductions for
§ 1.501(r)–3 Community health needs be eligible for assistance other than free hazardous liquid pipeline anomalies.
assessments. care, provides the individual with a The changes are addressed on an
* * * * * billing statement that indicates the individual basis and, where appropriate,
(c) * * * amount the individual owes for the care made applicable to the safety standards
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was not in the NAPSR resolution. The in September 2006, NAPSR also passed than leak survey standards for
language of the second part reads: ‘‘and a resolution [NAPSR Resolution 2006–3] transmission lines.
fix hazardous leaks that are discovered requesting the regulatory change to Title 49 CFR 192.706 requires
in accordance with § 192.703(c).’’ ‘‘Fix’’ Type B lines. transmission line leak surveys at
is hardly usual regulatory language and As for the comment that Type B leaks intervals not exceeding 15 months, but
has no specified definition or usage due to excavation damage may pose a at least once each calendar year, and
history in Part 192. The IUB and greater risk, the annual Type B report more frequently in densely populated
MichCon DTE Energy suggested that data for calendar year 2011 indicated areas. NAPSR believes that Type B
PHMSA use alternate language that that there were 289 leaks eliminated or gathering lines should be subject to the
removes a nonstandard term and an repaired by operators of onshore Type B same requirements, as Type B gathering
unnecessarily complicated rule gathering lines, with the leading cause lines can carry gas that is corrosive, and
reference by simply saying ‘‘and of leaks being external. Excavation gas leaks are a significant hazard on
promptly repair hazardous leaks that are damage is and has been recognized as a those low-stress pipelines. Therefore,
discovered.’’ high risk for Type B gathering lines. requiring leak surveys on Type B
The Northeast Gas Association This point was elaborated on in the Gas gathering lines is an appropriate and
suggested that PHMSA revise its Gathering Line Definition in the SNPRM necessary risk-management measure.
proposal to require operators of Type B (October 3, 2005; 70 FR 57536) and NAPSR also noted in their comments
regulated gathering lines to apply leak Final Rule (March 15, 2006; 71 FR that some Type B gathering lines are
survey methods in accordance with 13289), and served as the basis for the located under broad paved areas, where
§ 192.723 which provides the leak compliance activities for Type B lines electrical surveys that detect pipe
survey requirements for low-stress (damage prevention programs, damage may be difficult to perform, and
pipelines with a MAOP of less than 20 placement of line markers, and public leaking gas can migrate under the
percent specified minimum yield awareness programs). This amendment pavement and accumulate in
strength (SMYS). will add one more recognized risk surrounding structures. NAPSR
Response: As for the comment that control activity required on Type B recommends that leak detection surveys
PHMSA should wait until its gathering lines. should be required to ensure the safety
congressionally mandated review of Regarding the comment that PHMSA of these lines.
existing regulations for gas and should estimate the costs of compliance, As it stands, distribution lines in
hazardous liquid gathering lines is PHMSA performed a cost analysis by business districts must be surveyed each
complete, the study required by Section averaging the daily rate of two leak calendar year, with the remainder of
21 of the Pipeline Safety, Regulatory survey service providers. The average distribution lines subject to leak survey
Certainty, and Job Creation Act requires cost of surveying two miles of pipeline at frequencies driven by local
PHMSA to study and report to Congress per day equaled $600. The estimated conditions but at an interval that does
on: that approximately 3,650 miles of Type not exceed 5 years. Distribution lines,
(A) The sufficiency of existing Federal B gathering lines will be required to be per the regulations, are required to be
and state laws and regulations to ensure inspected annually at an average cost of odorized which provides members of
the safety of gas and hazardous liquid $300 per mile for an upper bound the public with a warning system for the
gathering lines; annual cost of approximately $1.1 period between surveys. The gas in
(B) The economic impacts, technical million. gathering lines is un-odorized, so the
practicability and challenges of However, leak surveys, while not public does not have any advance
applying existing Federal regulations to currently required for Type B gathering warning of line leaks outside of those
gathering lines that are not currently lines, are a widespread industry practice leak surveys. Leak surveys would serve
subject to Federal regulation when because they serve a business purpose as the warning bell.
compared to the public safety benefits; in helping to detect leaks, thereby Regarding the concerns raised by
and reducing lost gas and liability exposure. commenters about the cost of this
(C) Subject to a risk-based assessment, Although operators do not submit data proposal, under the current regulations,
the need to modify or revoke existing on the extent of these surveys, PHMSA Type B gathering lines are treated the
exemptions from Federal regulation for believes that approximately half of all same as transmission lines for design,
gas and hazardous liquid gathering Type B gathering line mileage that installation, construction, and initial
lines. would otherwise be affected by this testing and inspection. If the line in
The need to include leakage surveys proposal is already being inspected. question is composed of metal, the line
as a compliance activity was identified This is based on the fact that this is a must also comply with the same
between the publications of the widespread industry practice and until corrosion control requirements as
Supplemental Notice of Proposed Rule 2006, this was an existing regulatory transmission lines. Similar to
Making (SNPRM) titled: ‘‘Pipeline requirement. Therefore, a more realistic transmission lines, Type B gathering
Safety: Gas Gathering Line Definition: estimate of the actual incremental cost lines must be included in damage
Alternative Definition for Onshore Lines is approximately 50% of the upper prevention and public education
and Proposed Safety Standards,’’ bound of $1.1 million, or $0.55 million programs, have established MAOPs
published October 3, 2005; 70 FR 57536 per year. under § 192.619, and comply with the
[Docket No. RSPA–1998–4868; Notice The Northeast Gas Association, in a requirements for installing and
5], and the Final Rule of the same title comment on PHMSA’s published maintaining line markers.
published March 15, 2006; 71 FR 13289 NPRM, noted there were operational Because Type B gathering lines are
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[Docket No. PHMSA–1998–4868]. The similarities between Type B gathering regulated with many of the same
inclusion of leakage surveys as a lines and gas distribution lines that requirements as transmission lines, it
compliance action was not included in operate at similar, lower pressures, and would follow that Type B gathering
the Final Rule because it was beyond requested PHMSA apply leak survey lines and transmission lines have a
the scope of the SNPRM and the agency standards to Type B gathering lines that similar risk profile. Therefore, because
did not want to further delay the were more in line with leak survey transmission lines are subject to annual
rulemaking. During its annual meeting standards for distribution lines, rather leak surveys, Type B gathering lines
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should be subject to the same one unacceptable joint will make more. language used in the preamble and
requirement for safety reasons. City Utilities of Springfield, Missouri, additional clarification may be needed
While leak surveys are not currently suggested that we amend the language regarding PHMSA’s intent. PHMSA
required for Type B gathering lines, they to clarify that requalification is does not believe the proposed
are a widespread industry practice that necessary only if the joint failure is due requirements are as onerous as some of
help operators detect leaks early and to operator error. the commenters indicated, nor would
avoid loss of lives, gas and liability Nicor Gas (Nicor), while supporting there necessarily be a zero tolerance
exposure. When this voluntary practice the proposal to add a three-month grace policy in effect as a result of the
becomes a regulation it will provide a period in the requalification interval, proposed changes. PHMSA agrees there
standard and consistent level of safety does not support the proposed revision could be a number of factors including
to the American public and ensure the that would require requalification of the some beyond the joiners control such as
integrity of these lines. joiner if one joint is found unacceptable weather, equipment malfunctions and
Taking this into consideration, as well by the required pressure testing. Nicor material flaws, which could result in an
as the GPAC’s recommendation and the commented that the proposal is unacceptable joint. However, PHMSA
evaluation of public comments, PHMSA unnecessarily restrictive and not expects some evaluation would be done
has adopted § 192.9(d)(7) as proposed validated or supported by following any unacceptable joint, and in
with the minor modification of documentation from NAPSR. Nicor some cases evaluation may be necessary
substituting the word ‘‘fix’’ with noted that there are field conditions on a case-by-case basis. If an
‘‘repair.’’ and/or circumstances beyond the unacceptable joint is a result of a
(3) Qualifying Plastic Pipe Joiners joiner’s control (rain, snow, blowing factor(s) clearly beyond the joiner’s
§ 192.285(c) dirt, trench cave-ins, equipment control, PHMSA does not expect those
malfunctions and material flaws) that conditions to affect the requalification
Proposal: Section 192.285 contains would affect the joining process without of the joiner. Likewise, if an individual
requirements for qualifying persons to reflecting a lack of skill or proper fusing a joint realizes that it is a bad
make joints in plastic pipe. Under training. All these incidents may lead to
§ 192.285(c), ‘‘[a] person must be re- joint, cuts it out, and fuses another
an unacceptable joint. (acceptable) joint immediately
qualified under an applicable TPA also disagrees with the proposal
procedure, if during any 12-month following, PHMSA does not expect that
to impose a zero-failure tolerance the joiner would have to requalify. On
period that person: (1) Does not make standard for plastic pipe joiners and
any joints under that procedure; or (2) the other hand, if an unacceptable joint
commented that perfection in the is related to issues that are within the
has three joints or three percent of the performance of any task in any industry
joints made, whichever is greater under joiner’s control, that joiner would need
100 percent of the time is rarely, if ever, to be re-qualified. While PHMSA has
that procedure that are found achieved. TPA commented on the
unacceptable by testing under presented some general expectations,
contrast of the regulations in plastic
§ 192.513.’’ In its petition to amend the ultimate determination of the adequacy
joining versus welding of steel pipelines
regulations (2008–03–AC–1), NAPSR of an acceptable joint, whether or not
and noted that the existing regulations
noted that the current rule, with its 12- the joiner would need to be requalify,
for welders do not impose a zero-
month time period, requires detailed and what may constitute an adequate
tolerance standard, even though most
records of each individual joiner’s qualifying joining test would be up to
steel pipelines operate at higher
activities and sets the stage for which ever entity inspects the joint. In
pressures than plastic pipelines, and
requalification date ‘‘creep,’’ where a most cases, particularly for intrastate
would pose a higher safety risk to the
joiner must requalify at an earlier date systems, it would be up to the
public. The zero tolerance proposal for
every year. NAPSR commented that the plastic pipe joiners also fails to consider individual state.
existing regulatory language sets a very that all plastic pipe is required to be In response to the comments
low standard for joiner requalification pressure tested before going into service regarding the burden of this provision,
and noted that the large number of and that this testing provides an PHMSA notes that the changes may
operators requesting similar waivers additional layer of safety assurance that help reduce some of the current burden
demonstrates that a requalification plastic pipe joints are safe before associated with the paperwork, tracking
system like the one proposed in its pipeline operation begins. and record-keeping requirements that
resolution is acceptable and preferred AGA suggested that PHMSA analyze were associated with ‘‘three joints or
by pipeline operators. data on fusion failures, present the three percent of the joints made,
In the NPRM, based on the NAPSR information to the public and then whichever is greater’’ in the current
petition, PHMSA proposed to revise determine how best to address the issue. regulatory language. Regarding the
§ 192.285 to provide greater scheduling AGA further commented that the comments inquiring about data or other
flexibility and require requalification of amendment to prohibit the entire crew studies surrounding joints, PHMSA is
a joiner if any production joint is found from further fusion after one joint not aware of any studies showing that
unacceptable. failure until requalification occurs an individual who makes one
Comments: Center Point Energy (CPE) seems unnecessarily severe, is unacceptable joint will make more. On
noted that it is overly excessive to unsupported by statistical evidence and the other hand, PHMSA is not aware of
disqualify and retrain a joiner if one has the potential to create unexpected any data or studies that can guarantee
joint is found unacceptable during a 12- adverse consequences. that an individual who makes one
month period CPE suggested that Response: PHMSA reviewed the unacceptable joint won’t make another
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PHMSA leave § 192.285(c)(2) as written comments received on the topic unacceptable joint. The potential safety
and that quality assurance/quality including those that raised concerns of, issues surrounding an unacceptable
checks of potentially unacceptable and requested clarification on, the joint those are not addressed through
joints be accomplished through changes surrounding requalification if proper evaluation and requalification
§ 192.513 testing. CPE also queried one joint is found unacceptable. seem to outweigh any benefit with
whether PHMSA has data from a study PHMSA understands some of the continuing the qualification
to show that an individual who makes concerns may have been related to the requirements as they currently exist in
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Comments: We received no public or Comments: PHMSA received no remediation schedule must provide for
PAC comments on this proposal. public comments on this proposal. immediate repair conditions. To maintain
Response: PHMSA is unable to Response: PHMSA has adopted the safety an operator must provide for
incorporate ASME/ANSI B36.10M, proposal to repeal §§ 191.27 and 195.57. immediate repair conditions. To maintain
safety an operator must temporarily reduce
‘‘Standard for Welded and Seamless (10) Calculating Pressure Reductions for the operating pressure or shut down the
Wrought Steel Pipe’’ due to the Hazardous Liquid Pipeline Integrity pipeline until the operator completes the
standards availability requirement Anomalies § 195.452(h)(4)(i) repair of these conditions. An operator must
described in Section 24 of the ‘‘Pipeline calculate the temporary reduction in
Safety, Regulatory Certainty, and Job Proposal: Section 195.452(h)(4)(i)
specifies the actions that an operator of operating pressure using the criteria in
Creation Act of 2011’’ (Pub. L. 112–90, paragraph (h)(4)(i)(B) of this section. If no
January 3, 2012). Section 24 added a a hazardous liquid pipeline must take
suitable remaining strength calculation
new public availability requirement for after discovering an immediate repair method can be identified, a minimum 20
documents incorporated by reference condition. One of those actions is a percent or greater operating pressure
temporary reduction in operating reduction must be implemented until the
after January 3, 2013. The law stated
pressure as determined under the anomaly is repaired. An operator must treat
that beginning 1 year after the date of
formula provided in section 451.6.2.2 the following conditions as immediate repair
enactment of this subsection, the
(b) of ASME/ANSI B31.4, ‘‘Pipeline conditions.’’
Secretary may not issue guidance or a
Transportation Systems for Liquid
regulation pursuant to this chapter that The AOPL commented that the
Hydrocarbons and Other Liquids.’’ The
incorporates by reference any proposed language requiring the
particular focus of that pressure
documents or portions thereof unless calculation of pressure reductions for
reduction formula is corrosion.
the documents or portions thereof are detected anomalies should be modified
However, corrosion is only one of the
made available to the public, free of to appropriately reference suitable
threats that could cause an immediate
charge, on an Internet Web site. repair condition under calculation methods.
This section was further amended on § 195.452(h)(4)(i). API noted that § 195.452(h)(4)(i)(B)
August 9, 2013. The current law In a July 17, 2007, Final Rule (72 FR already allows the use of PR–3–805
continues to prohibit the Secretary from 39017), PHMSA sought to modify (RSTRENG), modified PR–3–805
issuing a regulation that incorporates by § 195.452(h)(4)(i) to provide for (RSTRENG), or a suitable alternative
reference any document unless that alternative methods of calculating a remaining strength calculation method
document is available to the public, free pressure reduction for immediate repair to be used, and therefore already fully
of charge, but removes the Internet Web conditions caused by threats other than covers the calculation of a temporary
site requirements (Pub. L. 113–30, corrosion. The Office of the Federal reduction in operating pressure. The
August 9, 2013). PHMSA will address Register was unable to incorporate that API suggests that the following sentence
this proposal in a future rulemaking change due to inaccurate amendatory in the proposed section is redundant: ‘‘If
action. instructions. In the NPRM, PHMSA the formula is not applicable to the type
(9) Offshore Pipeline Condition Reports again proposed to revise of anomaly or would produce a higher
§§ 191.27 and 195.57 § 195.452(h)(4)(i) to make the same operating pressure, an operator must use
change as published in the July 17, an alternative acceptable method to
Proposal: In the NPRM, PHMSA 2007, Final Rule, with corrected calculate a reduced operating pressure.’’
proposed to remove §§ 191.27 and amendatory instructions.
195.57. Sections 191.27 and 195.57 Comments: In response to our The LPAC suggested the following
require operators to submit a report to proposal, the TransCanada Corporation language:
PHMSA within 60 days of completing commented that it acknowledges the § 195.452(h)(4)(i): ‘‘Immediate repair
the underwater inspections of pipelines limitations of the current language in conditions. An operator’s evaluation and
in the Gulf of Mexico required by § 195.452(h)(4)(i) and believes a revision remediation schedule must provide for
§§ 192.612(a), and 195.413(a). to the language in this section is immediate repair conditions. To maintain
Sections 192.612(a) and 195.413(a) no appropriate. However, since safety, an operator must temporarily reduce
longer require operators to perform an § 195.452(h)(4)(i)(B) provides for the the operating pressure or shut down the
pipeline until the operator completes the
underwater inspection of all pipelines calculation of the remaining strength
repair of these conditions. An operator must
in the Gulf and its inlets. (See also Pub. using methods that include, ‘‘but are not calculate the temporary reduction in
L. 102–508 (Oct. 24, 1992) (modifying limited to,’’ ASME/ANSI B31G, operating pressure using the formulas
the statutory mandate for underwater ‘‘Manual for Determining the Remaining referenced in paragraph (h)(4)(i)(B) of this
inspection, reporting and reburial of Strength of Corroded Pipelines,’’ section. If no suitable remaining strength
pipelines in the Gulf and its inlets). (ASME/ANSI B31G) or AGA Pipeline calculation method can be identified, a
Rather, those regulations call for Research Committee, Project PR–3–805, minimum 20 percent or greater operating
periodic, risk-based inspections of ‘‘A Modified Criterion for Evaluating the pressure reduction, based on actual operating
shallow-water pipelines. The filing of a Remaining Strength of Corroded Pipe,’’ pressure for two months prior to the date of
written report within 60 days of (PR–3–805 (RSTRING)), they do not inspection, must be implemented until the
completing all of those inspections is believe a reference to the design anomaly is repaired. An operator must treat
requirements of § 195.106 is necessary. the following conditions as immediate repair
not consistent with such an action.
TransCanada commented that the ability conditions: [. . .]’’
Additionally, sections 192.612(c) and
195.413(c) require operators to file their to use alternative methods for Response: PHMSA believes both
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electronic/telephonic reports with the calculating a pressure reduction would commenters were trying to make similar
National Response Center within 24 be incorporated with only a reference to changes. In the Final Rule, PHMSA is
hours of discovering that a pipeline in § 195.452(h)(4)(i)(B). They suggested the adopting LPAC’s suggested language as
those areas is exposed or a hazard to following language in lieu of what it best clarifies that an operator must
navigation, which is sufficient to meet PHMSA has proposed: calculate remaining strength or reduce
PHMSA’s current information collection § 195.452(h)(4)(i): ‘‘Immediate repair operating pressure until a repair can be
needs. conditions. An operator’s evaluation and completed.
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especially if changes are made between opportunity to formally incorporate by there are no commercially used pipeline
annual submissions. reference Appendix B to API Std 1104 welding systems in the United States to
Response: In response to TPA’s and for in-service (also known as ‘‘live line’’) which API Std 1104, section 13 can be
Oleksa’s concern about submitting the welding. Oleska suggested that the applied. Not adopting API Std 1104,
data twice, operators will continue to language of the proposed revision section 13, will prevent an operator
make only one NPMS submission would be clearer if we changed ‘‘pipe from using a potentially less safe
following the guidelines in the NPMS and components’’ to read ‘‘pipe or welding system without a PHMSA
Operator Standards Manual on the components.’’ special permit review.
NPMS Web site Panhandle commented that the INGAA suggested that PHMSA use
(www.npms.phmsa.dot.gov). This Final proposed language for § 192.229(c)(1) the Final Rule as an opportunity to
Rule imposes no additional submission contains an oversight related to this formally incorporate by reference
requirements. In response to the equivalence. The section says, in part: Appendix B to API Std 1104 for in-
concern about the NPMS’s and A welder or welding operator service (‘‘live line’’) welding. Parts 192
PHMSA’s capability to process all the qualified under § 192.227(a)— and 195 currently require that all
gas, LNG plant operator and liquid (1) May not weld on pipe to be welding procedures be qualified to API
operator submissions received on or operated at a pressure that produces a Std 1104, section 5 or ASME BPVC,
before March 15 and June 15, hoop stress of 20 percent or more of section IX, and that all welders be
respectively, PHMSA encourages SMYS unless within the preceding six qualified to API Std 1104, section 6 or
operators to make their submissions calendar months the welder or welding ASME BPVC, section IX. API Std 1104,
early beginning on January 1 of each operator has had one weld tested and Appendix B is only applicable to in-
year. In the Final Rule, PHMSA is found acceptable under section 6 or service welds on live or ‘‘hot’’ pipelines,
adopting the amendment to the NPMS section 9 of API Std 1104 (incorporated with pressurized product in the pipe.
as proposed. by reference, see § 192.7). The qualification requirements of
According to Panhandle, sections 6 Appendix B are optimized for in-service
(14) Welders vs. Welding Operators
and 9 of API Std 1104 relate to welds, and differ greatly from API Std
§§ 192.225, 192.227, 192.229, 195.214,
workmanship criteria only. The 1104, sections 5 and 6 and ASME BPVC,
195.222
proposed language would appear to section IX. Thus, adding API Std 1104,
Proposal: The welding provisions in exclude qualification of a welding Appendix B to the Final Rule is a
Subpart E of Part 192 and Subpart D of operator whose welds are regularly significant change that is outside the
Part 195 allow qualification of welders being assessed per the criteria in API scope of this rule. We will consider this
in accordance with API Standard 1104, Std 1104, Appendix A which is change for a future regulatory action.
‘‘Welding of the ASME Pipelines and regarded as being equivalent to ASME Based upon further review by PHMSA
Related Facilities,’’ (API Std 1104), BPVC, section IX. It is reasonable to of Part 192, Appendix C, PHMSA
section 6 or ASME Boiler and Pressure allow qualification for a welding decided that adding welding operators
Vessel Code., section IX: ‘‘Qualification operator whose work has been for Appendix C qualification in
Standard for Welding and Brazing acceptable under the Appendix A § 192.227(b) would be inappropriate for
Procedures, Welders, Brazers, and criteria. Panhandle therefore suggested the following reasons:
Welding and Brazing Operators,’’ that PHMSA modify the proposed (1) Qualification of welding operators
(ASME BPVC, section IX). In the NPRM, language in the notice to read: can be, and is more appropriately
PHMSA proposed to add references to performed to API Std 1104, section 12,
additional qualification standards in A welder or welding operator qualified
under § 192.227(a) may not weld on pipe to instead of Appendix C;
API Std 1104, such as sections 12 and (2) Appendix C is primarily used for
be operated at a pressure that produces a
13 for welders and welding operators of hoop stress of 20 percent or more of SMYS lower pressure, smaller diameter
mechanized and automated welding unless within the preceding 6 calendar distribution lines, which are welded by
equipment. The addition of these months the welder or welding operator has welders, not welding operators; and
qualification references was intended to had one weld tested and found acceptable (3) The language in Appendix C was
follow current industry practice. These under section 6, section 9 or Appendix A of written for qualification of welders, and
standards have specific processes to API Std 1104, as applicable (incorporated by may not be appropriate for qualification
ensure that qualified personnel are used reference, see § 192.7). of welding operators.
for welding processes whether they are Response: The Final Rule allows We agree with the comments that API
performed by welders or welding welds to be evaluated to API Std 1104, 1104, Appendix A should be included
operators. section 9 or Appendix A, and eliminates as a qualification reference. When we
Comments: EPPG commented that the the requirement that the weld be first proposed to add the relevant references
proposed language appears to not allow evaluated to section 9, before using to welding qualification standards to be
for the qualification of a welding Appendix A. Evaluating the welds first consistent with industry practice, we
operator whose welds are regularly according to section 9 incurs intended to include the Appendix A
being assessed per the criteria in API unnecessary time and cost without any reference, a widely accepted standard.
Std 1104, Appendix A, which is benefit. Appendix A is now cited in the final
regarded as being equivalent to section PHMSA re-evaluated its proposal to regulations applicable to welding and
9. EPPG suggested a revision of the add additional references to welding operators.
proposed language of § 192.227(a) to qualification standards in API Std 1104.
read: ‘‘under section 6, or section 9 or PHMSA finds that adding API Std 1104, (15) Components Fabricated by Welding
§ 192.153
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Appendix A, as applicable of API Std section 13 (‘‘Automatic Welding
1104 (incorporated by reference, see Without Filler Metal Additions’’) is Proposal: Pressure vessels can be
§ 192.7).’’ [Proposed deletion indicated inconsistent with pipeline safety. API found in meter stations, compressor
by strikeout; proposed addition in bold]. Std 1104, section 13 is not used on stations and other pipeline facilities to
INGAA recommended that while regulated pipelines and would be a facilitate the removal of liquids and
PHMSA is amending the welding major change in girth welding other materials from the gas stream.
regulations, PHMSA should take the standards. Also, for practical purposes, These vessels are designed, fabricated
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![12772 Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations
and tested in accordance with the INGAA noted that station piping often (16) Odorization of Gas Transmission
requirements of ASME Boiler & Pressure includes fabricated sections that are Lateral Lines § 192.625
Vessel Code, section VIII Rules for assembled at the construction site. Proposal: Section 192.625 contains
Construction of Pressure Vessels,’’ as Many of these sections, such as requirements for operators to odorize
required by § 192.153 and compressor bottles, coolers and inlet combustible gas in a transmission line
§ 192.165(b)(3), and the additional test scrubbers and separators are tested and in Class 3 or Class 4 locations ‘‘so that
requirements of § 192.505(b). certified by their manufacturers. at a concentration in air of one-fifth of
In the NPRM, PHMSA proposed that Requiring a second test at the the lower explosive limit, the gas is
because the standard ASME pressure construction site as proposed would readily detectable by a person with a
vessel test in ASME BPVC, section VIII, depart sharply from common practice, normal sense of smell.’’ Certain
division 1 is 1.3 times MAOP, an add costs that are not justified by a exceptions are recognized by regulation,
operator must specify the correct test safety benefit and potentially invalidate including for a lateral line, ‘‘which
pressure when placing an order for an the manufacturers’ compliance transports gas to a distribution center,
ASME vessel to ensure it is designed certificates.
[if] at least 50 percent of the length of
and tested to the requirements of 49 Kern River further commented that
that line is in a Class 1 or Class 2
CFR part 192. Unless a vessel is station piping is commonly tested in
specially ordered with a test pressure of several segments and it is not common location.’’ This section does not specify
1.5 times MAOP as prescribed by the practice to include and retest ASME a clear method for calculating the length
purchaser, the vessel will be tested in code vessels since they are certified by of a lateral line, and that has led to
accordance with the standard test factor the manufacturers and retesting would inconsistencies in applying the
of 1.3. If the vessel is not tested to 1.5 require dewatering. INGAA advised odorization requirement. In the NPRM,
times the MAOP, it cannot be used in PHMSA to adopt an alternate PHMSA proposed to amend
a compressor or meter station, or other clarification that these components do § 192.625(b)(3) to state that the length of
Class 3 or Class 4 locations. The failure not require testing beyond the ASME a lateral line, for purposes of calculating
to meet this requirement can potentially code. If PHMSA adopts the current whether at least 50 percent of the line
lead to exceeding the design parameters recommendation, it should clarify that is in a Class 1 or Class 2 location, be
of the vessel during subsequent testing the amendment applies to components measured between the distribution
of the pipeline system. placed into service after the center and the first upstream connection
The pressure test requirements in amendment’s effective date. to the transmission line.
ASME BPVC, section VIII were lowered Response: PHMSA has incorporated Comments: Texas Oil and Gas
from a test factor of 1.5 to 1.3 by an by reference ASME BPVC for pressure Association commented, and API
earlier edition. PHMSA proposed to add vessels. The revised ASME BPVC, supported this comment, that PHMSA’s
§ 192.153 to clearly specify the design section VII, division 1 has changed attempt to better define which natural
and test requirements for pressure pressure testing standards from 1.5 gas transmission lateral pipelines are
vessels in meter stations, compressor times MAOP to 1.3 times MAOP. This subject to the odorization requirement
stations, and other locations that are proposal is not a change to the current may create the unintended consequence
tested to Class 3 requirements. Under pressure testing requirements found in of adversely impacting industrial
the proposal, all ASME pressure vessels Part 192, but simply a clarification to facility (refinery) operations and
subject to § 192.153 and § 192.165(b)(3) ensure a clearer understanding of product quality in addition to increasing
would be designed and tested at a PHMSA’s pressure testing requirements emissions. TransCanada Corporation
pressure that is 1.5 times the MAOP, in for certain ASME BPVC vessels located noted that the proposed amendment’s
lieu of the standard ASME BPVC, in compressor stations, meter stations apparent distinction between lateral and
section VIII test pressure of 1.3 times the and other Class 3 or Class 4 locations. transmission lines appears to lack logic,
MAOP. Additionally, PHMSA proposed The pressure testing requirements for as it allows parts of a line originally
to revise § 192.165(b)(3) reference to this pipelines in the PSR (which by considered to be a ‘‘lateral’’ line to
requirement. definition includes pressure vessels, change classification due to
Comments: Kern River, INGAA and meter stations, compressor stations and introduction of a branch. TransCanada
Northern Natural Gas maintained that other facilities used to transport gas as further noted that the industry is not
this proposal is not a simple defined in Part 192 and ASME/ANSI aware of, nor has PHMSA presented in
clarification but a change from the B31.8) in Class 3 and 4 areas, as well as the preamble, statistical evidence that
previous understanding and practice of those facilities located in Class 1 and this understanding of lateral has caused
both PHMSA and the operators. If the Class 2 which are explicitly required by safety issues resulting from operators
proposed regulation is applied § 192.505(b), requires a pressure test applying this definition to exempt
retroactively, this change will place equal to a minimum of 1.5 times the certain lines from odorization with
many facilities constructed after the MAOP. The testing requirements of commensurate safety benefits.
change in the pressure test requirements § 192.505(b) have not been revised and TransCanada submits that the definition
in ASME BPVC, section VIII, as well as state that in a Class 1 or Class 2 location, of ‘‘lateral’’ most commonly used by the
many facilities uprated under special each compressor station regulator industry more than adequately serves
permits, in violation of ASME BPVC, station, and measuring station, must be the interest of public safety. It also
sections I and II. INGAA noted that tested to at least Class 3 location test noted that ‘‘laterals are not distinct
these sections of Part 192 and the ASME requirements. This clarification of code classification of lines; rather, ‘laterals’
BPVC revision history make it clear that requirements are to ensure that Industry are described according to their function
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the proposed rule will require a number does not incorrectly use the newer (e.g., transmission, distribution or
of operators to make substantial and ASME BPVC standard for pressure gathering).’’
costly changes. Northern Natural Gas testing even though that was never the INGAA had similar comments and
commented that retesting and replacing requirement. This clarification will not suggested that PHMSA convene a public
of these in-service components would lead to additional cost measures, and hearing or workshop to develop the
be unnecessary, very expensive, and therefore, PHMSA is adopting this fundamental regulatory changes needed
take several years to complete. amendment as proposed. to align its policy objectives with
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Further, the Office of Information and ■ 3. In § 191.25 paragraph (a) is revised or contact the PHMSA Geographic
Regulatory Affairs has not designated to read as follows: Information Systems Manager at (202)
this Final Rule as a significant energy 366–4595.
§ 191.25 Filing safety-related condition
action.
reports. PART 192—TRANSPORTATION OF
List of Subjects (a) Each report of a safety-related NATURAL AND OTHER GAS BY
49 CFR Part 191 condition under § 191.23(a) must be PIPELINE: MINIMUM FEDERAL
filed (received by OPS within five SAFETY STANDARDS
Pipeline Safety, Reporting, and working days, not including Saturday,
recordkeeping requirements. Sunday, or Federal Holidays) after the ■ 6. The authority citation for Part 192
49 CFR Part 192 day a representative of the operator first is revised to read as follows:
determines that the condition exists, but Authority: 49 U.S.C. 5103, 60102, 60104,
Fire prevention, Incorporation by not later than 10 working days after the 60108, 60109, 60110, 60113, 60116 and
reference, Pipeline safety, Security day a representative of the operator 60118, 60137; and 49 CFR 1.97.
measures discovers the condition. Separate
conditions may be described in a single ■ 7. In § 192.3, definitions for ‘‘Welder’’
49 CFR Part 195
report if they are closely related. Reports and ‘‘Welding operator’’ are added in
Ammonia, Carbon dioxide, may be transmitted by electronic mail to alphabetical order to read as follows:
Incorporation by reference, Petroleum, InformationResourcesManager@dot.gov
Pipeline safety, Reporting and § 192.3 Definitions.
or by facsimile at (202) 366–7128.
recordkeeping requirements. * * * * *
* * * * *
In consideration of the foregoing, 49 Welder means a person who performs
CFR Chapter I is amended as follows: § 191.27 [Removed]. manual or semi-automatic welding.
■ 4. Section 191.27 is removed. Welding operator means a person who
PART 191—TRANSPORTATION OF operates machine or automatic welding
NATURAL AND OTHER GAS BY ■ 5. Section 191.29 is added to read as equipment.
PIPELINE; ANNUAL REPORTS, follows:
INCIDENT REPORTS, AND SAFETY- ■ 8. In § 192.9, paragraph (d)(7) is added
§ 191.29 National Pipeline Mapping to read as follows:
RELATED CONDITION REPORTS System.
(a) Each operator of a gas transmission § 192.9 What requirements apply to
■ 1. The authority citation for Part 191 gathering lines?
is revised to read as follows: pipeline or liquefied natural gas facility
must provide the following geospatial * * * * *
Authority: 49 U.S.C. 5121, 60102, 60103, data to PHMSA for that pipeline or (d) * * *
60104, 60108, 60117, 60118, 60124, 60132,
facility: (7) Conduct leakage surveys in
and 49 CFR 1.97.
(1) Geospatial data, attributes, accordance with § 192.706 using leak
■ 2. In § 191.7 paragraphs (a) and (b) are metadata and transmittal letter detection equipment and promptly
revised and paragraph (e) is added to appropriate for use in the National repair hazardous leaks that are
read as follows: Pipeline Mapping System. Acceptable discovered in accordance with
formats and additional information are § 192.703(c).
§ 191.7 Report submission requirements.
specified in the NPMS Operator * * * * *
(a) General. Except as provided in Standards Manual available at
paragraphs (b) and (e) of this section, an www.npms.phmsa.dot.gov or by ■ 9. In § 192.65, paragraph (a) is revised
operator must submit each report contacting the PHMSA Geographic to read as follows:
required by this part electronically to Information Systems Manager at (202)
the Pipeline and Hazardous Materials § 192.65 Transportation of pipe.
366–4595.
Safety Administration at http:// (2) The name of and address for the (a) Railroad. In a pipeline to be
portal.phmsa.dot.gov/pipeline unless an operator. operated at a hoop stress of 20 percent
alternative reporting method is (3) The name and contact information or more of SMYS, an operator may not
authorized in accordance with of a pipeline company employee, to be install pipe having an outer diameter to
paragraph (d) of this section. displayed on a public Web site, who wall thickness of 70 to 1, or more, that
(b) Exceptions: An operator is not will serve as a contact for questions is transported by railroad unless the
required to submit a safety-related from the general public about the transportation is performed by API RP
condition report (§ 191.25) operator’s NPMS data. 5L1 (incorporated by reference, see
electronically. (b) The information required in § 192.7).
* * * * * paragraph (a) of this section must be * * * * *
(e) National Pipeline Mapping System submitted each year, on or before March ■ 10. In the table in § 192.112,
(NPMS). An operator must provide the 15, representing assets as of December paragraph (e) is revised to read as
NPMS data to the address identified in 31 of the previous year. If no changes follows:
the NPMS Operator Standards manual have occurred since the previous year’s
available at www.npms.phmsa.dot.gov submission, the operator must comply § 192.112 Additional design requirements
or by contacting the PHMSA Geographic with the guidance provided in the for steel pipe using alternative maximum
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Information Systems Manager at (202) NPMS Operator Standards manual allowable operating pressure.
366–4595. available at www.npms.phmsa.dot.gov * * * * *
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![Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 12779
reference, see § 192.7). Appendix A of ASME/ANSI, Manufacturers § 192.925 What are the requirements for
API Std 1104 may not be used to accept Standardization Society of the Valve using External Corrosion Direct
cracks. and Fittings Industry, Inc. (MSS) Assessment (ECDA)?
■ 17. In § 192.243, paragraph (e) is specifications, or by unit strength * * * * *
revised to read as follows: calculations as described in § 192.143. (b) General requirements. An operator
that uses direct assessment to assess the
§ 192.243 Nondestructive testing. § 192.505 [Amended] threat of external corrosion must follow
* * * * * ■ 21. In § 192.505, paragraph (d) is the requirements in this section, in
(e) Except for a welder or welding removed and paragraph (e) is ASME/ANSI B31.8S (incorporated by
operator whose work is isolated from redesignated as paragraph (d). reference, see § 192.7), section 6.4, and
the principal welding activity, a sample in NACE SP0502 (incorporated by
of each welder or welding operator’s ■ 22. In § 192.620, paragraph (c)(1) and reference, see § 192.7). An operator must
work for each day must be the first sentence of paragraph (c)(8) are develop and implement a direct
nondestructively tested, when revised to read as follows: assessment plan that has procedures
nondestructive testing is required under addressing pre-assessment, indirect
§ 192.241(b). § 192.620 Alternative maximum operating inspection, direct examination, and post
pressure for certain steel pipelines.
* * * * * assessment. If the ECDA detects
* * * * * pipeline coating damage, the operator
■ 18. In § 192.285, paragraph (c) is
revised to read as follows: (c) * * * must also integrate the data from the
(1) For pipelines already in service, ECDA with other information from the
§ 192.285 Plastic pipe: Qualifying persons data integration (§ 192.917(b)) to
to make joints.
notify the PHMSA pipeline safety
regional office where the pipeline is in evaluate the covered segment for the
* * * * * service of the intention to use the threat of third party damage and to
(c) A person must be re-qualified address the threat as required by
alternative pressure at least 180 days
under an applicable procedure once § 192.917(e)(1).
before operating at the alternative
each calendar year at intervals not * * * * *
MAOP. For new pipelines, notify the
exceeding 15 months, or after any (2) Indirect inspection. In addition to
PHMSA pipeline safety regional office
production joint is found unacceptable the requirements in ASME/ANSI
of planned alternative MAOP design
by testing under § 192.513. B31.8S, section 6.4 and in NACE
and operation at least 60 days prior to
* * * * * the earliest start date of either pipe SP0502, section 4, the plan’s procedures
■ 19. Section 192.305 is revised to read manufacturing or construction for indirect inspection of the ECDA
as follows: activities. An operator must also notify regions must include—
§ 192.305 Inspection: General. the state pipeline safety authority when * * * * *
Each transmission line and main must the pipeline is located in a state where ■ 25. Section 192.949 is revised to read
be inspected to ensure that it is PHMSA has an interstate agent as follows:
constructed in accordance with this agreement or where an intrastate
pipeline is regulated by that state. § 192.949 How does an operator notify
subpart. An operator must not use PHMSA?
operator personnel to perform a * * * * *
required inspection if the operator An operator must provide any
(8) A Class 1 and Class 2 location can
personnel performed the construction notification required by this subpart
be upgraded one class due to class
task requiring inspection. Nothing in by—
changes per § 192.611(a). * * *
this section prohibits the operator from (a) Sending the notification by
* * * * * electronic mail to
inspecting construction tasks with
operator personnel who are involved in ■ 23. In § 192.805 paragraph (i) is InformationResourcesManager@dot.gov;
other construction tasks. revised to read as follows: or
(b) Sending the notification by mail to
■ 20. In § 192.503, a new paragraph (e) § 192.805 Qualification program. ATTN: Information Resources Manager,
is added to read as follows: * * * * * DOT/PHMSA/OPS, East Building, 2nd
§ 192.503 General requirements. (i) After December 16, 2004, notify the Floor, E22–321, 1200 New Jersey Ave.
* * * * * Administrator or a state agency SE., Washington, DC 20590.
(e) If a component other than pipe is participating under 49 U.S.C. Chapter
601 if the operator significantly PART 195—TRANSPORTATION OF
the only item being replaced or added
modifies the program after the HAZARDOUS LIQUIDS BY PIPELINE
to a pipeline, a strength test after
installation is not required, if the administrator or state agency has ■ 26. The authority citation for Part 195
manufacturer of the component certifies verified that it complies with this is revised to read as follows:
that: section. Notifications to PHMSA may be
(1) The component was tested to at submitted by electronic mail to Authority: 49 U.S.C. 5103, 60102, 60104,
least the pressure required for the 60108, 60109, 60116, 60118, 60132, 60137,
InformationResourcesManager@dot.gov,
and 49 CFR 1.97.
pipeline to which it is being added; or by mail to ATTN: Information
(2) The component was manufactured Resources Manager DOT/PHMSA/OPS, ■ 27. In § 195.2, the definitions of
under a quality control system that East Building, 2nd Floor, E22–321, New ‘‘alarm’’ and ‘‘hazardous liquid’’ are
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ensures that each item manufactured is Jersey Avenue SE., Washington, DC revised and definitions for ‘‘welder’’
at least equal in strength to a prototype 20590. and ‘‘welder operator’’ are added in
and that the prototype was tested to at appropriate alphabetical order to read as
least the pressure required for the ■ 24. In § 192.925, the introductory text follows:
pipeline to which it is being added; or of paragraph (b) and the introductory
(3) The component carries a pressure text of paragraph (b)(2) are revised to § 195.2 Definitions.
rating established through applicable read as follows: * * * * *
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![12780 Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations
Alarm means an audible or visible § 195.61 National Pipeline Mapping Appendix A of API Std 1104
means of indicating to the controller System. (incorporated by reference, see § 195.3),
that equipment or processes are outside (a) Each operator of a hazardous or section IX of ASME Boiler and
operator-defined, safety-related liquid pipeline facility must provide the Pressure Vessel Code (BPVC)
parameters. following geospatial data to PHMSA for (incorporated by reference, see § 195.3).
* * * * * that facility: The quality of the test welds used to
Hazardous liquid means petroleum, (1) Geospatial data, attributes, qualify welding procedures must be
petroleum products, anhydrous metadata and transmittal letter determined by destructive testing.
ammonia, or ethanol. appropriate for use in the National * * * * *
* * * * * Pipeline Mapping System. Acceptable
formats and additional information are ■ 35. In § 195.222 the heading,
Welder means a person who performs paragraph (a), the introductory text of
manual or semi-automatic welding. specified in the NPMS Operator
Standards manual available at paragraph (b), and paragraph (b)(2) are
Welding operator means a person who revised to read as follows:
operates machine or automatic welding www.npms.phmsa.dot.gov or by
equipment. contacting the PHMSA Geographic
§ 195.222 Welders and welding operators:
Information Systems Manager at (202) Qualification of welders and welding
■ 28. In § 195.56 paragraph (a) is revised 366–4595. operators.
to read as follows: (2) The name of and address for the
operator. (a) Each welder or welding operator
§ 195.56 Filing safety-related condition must be qualified in accordance with
reports. (3) The name and contact information
of a pipeline company employee, to be section 6, section 12 or Appendix A of
(a) Each report of a safety-related displayed on a public Web site, who API Std 1104 (incorporated by
condition under § 195.55(a) must be will serve as a contact for questions reference, see § 195.3), or section IX of
filed (received by OPS) within five from the general public about the ASME Boiler and Pressure Vessel Code
working days (not including Saturday, operator’s NPMS data. (BPVC), (incorporated by reference, see
Sunday, or Federal Holidays) after the (b) This information must be § 195.3), except that a welder or welding
day a representative of the operator first submitted each year, on or before June operator qualified under an earlier
determines that the condition exists, but 15, representing assets as of December edition than an edition listed in § 195.3,
not later than 10 working days after the 31 of the previous year. If no changes may weld but may not re-qualify under
day a representative of the operator have occurred since the previous year’s that earlier edition.
discovers the condition. Separate submission, the operator must refer to (b) No welder or welding operator
conditions may be described in a single the information provided in the NPMS may weld with a welding process
report if they are closely related. Reports Operator Standards manual available at unless, within the preceding 6 calendar
may be transmitted by electronic mail to www.npms.phmsa.dot.gov or contact the months, the welder or welding operator
InformationResourcesManager@dot.gov, PHMSA Geographic Information has—
or by facsimile at (202) 366–7128. Systems Manager at (202) 366–4595. * * * * *
* * * * *
§ 195.64 [Removed] (2) Had one weld tested and found
§ 195.57 [Removed] acceptable under section 9 or Appendix
■ 32. In § 195.64, paragraph (c)(1)(iii) is A of API Std 1104 (incorporated by
■ 29. Section 195.57 is removed. removed. reference, see § 195.3).
■ 30. In § 195.58, paragraphs (a) and (b) ■ 33. Section 195.204 is revised to read ■ 36. In § 195.228, paragraph (b) is
are revised and a new paragraph (e) is as follows: revised to read as follows:
added to read as follows:
§ 195.204 Inspection—general. § 195.228 Welds and welding inspection:
§ 195.58 Report submission requirements.
Inspection must be provided to ensure Standards of acceptability.
(a) General. Except as provided in that the installation of pipe or pipeline * * * * *
paragraphs (b) and (e) of this section, an systems is in accordance with the
operator must submit each report (b) The acceptability of a weld is
requirements of this subpart. Any determined according to the standards
required by this part electronically to operator personnel used to perform the
PHMSA at http://opsweb.phmsa.dot.gov in section 9 or Appendix A of API Std
inspection must be trained and qualified 1104 (incorporated by reference, see
unless an alternative reporting method in the phase of construction to be
is authorized in accordance with § 195.3). Appendix A of API Std 1104
inspected. An operator must not use may not be used to accept cracks.
paragraph (d) of this section. operator personnel to perform a
(b) Exceptions: An operator is not required inspection if the operator ■ 37. In § 195.234, paragraph (d) is
required to submit a safety-related personnel performed the construction revised to read as follows:
condition report (§ 195.56) task requiring inspection. Nothing in
electronically. this section prohibits the operator from
§ 195.234 Welds: Nondestructive testing.
* * * * * inspecting construction tasks with * * * * *
(e) National Pipeline Mapping System operator personnel who are involved in (d) During construction, at least 10
(NPMS). An operator must provide other construction tasks. percent of the girth welds made by each
NPMS data to the address identified in ■ 34. In § 195.214, paragraph (a) is welder and welding operator during
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the NPMS Operator Standards Manual revised to read as follows: each welding day must be
available at www.npms.phmsa.dot.gov nondestructively tested over the entire
or by contacting the PHMSA Geographic § 195.214 Welding procedures. circumference of the weld.
Information Systems Manager at (202) (a) Welding must be performed by a * * * * *
366–4595. qualified welder or welding operator in
■ 31. Section 195.61 is added to read as accordance with welding procedures ■ 38. In § 195.307 paragraphs (c) and (d)
follows: qualified under section 5, section 12 or are revised to read as follows:
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![Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 12781
§ 195.307 Pressure testing aboveground the formulas referenced in paragraph DEPARTMENT OF COMMERCE
breakout tanks. (h)(4)(i)(B) of this section. If no suitable
* * * * * remaining strength calculation method National Oceanic and Atmospheric
(c) For aboveground breakout tanks can be identified, an operator must Administration
built to API Std 650 (incorporated by implement a minimum 20 percent or
reference, see § 195.3) and first placed greater operating pressure reduction, 50 CFR Part 679
in service after October 2, 2000, testing based on actual operating pressure for [Docket No. 141021887–5172–02]
must be in accordance with sections two months prior to the date of
7.3.5 and 7.3.6 of API Standard 650 inspection, until the anomaly is RIN 0648–XD813
(incorporated by reference, see § 195.3). repaired. An operator must treat the
(d) For aboveground atmospheric following conditions as immediate Fisheries of the Exclusive Economic
pressure breakout tanks constructed of repair conditions: Zone Off Alaska; Reallocation of
carbon and low alloy steel, welded or Pollock in the Bering Sea and Aleutian
* * * * * Islands
riveted, and non-refrigerated tanks built
to API Std 650 or its predecessor (m) How does an operator notify
PHMSA? An operator must provide any AGENCY: National Marine Fisheries
Standard 12 C that are returned to Service (NMFS), National Oceanic and
service after October 2, 2000, the notification required by this section by:
Atmospheric Administration (NOAA),
necessity for the hydrostatic testing of (1) Sending the notification by Commerce.
repair, alteration, and reconstruction is electronic mail to ACTION: Temporary rule.
covered in section 12.3 of API Standard InformationResourcesManager@dot.gov;
653 (incorporated by reference, see or SUMMARY: NMFS is reallocating the
§ 195.3). (2) Sending the notification by mail to projected unused amounts of the
* * * * * ATTN: Information Resources Manager, Community Development Quota pollock
■ 39. In § 195.428, paragraph (c) is DOT/PHMSA/OPS, East Building, 2nd directed fishing allowances from the
revised to read as follows: Floor, E22–321, 1200 New Jersey Ave Aleutian Islands subarea to the Bering
SE., Washington, DC 20590. Sea subarea. This action is necessary to
§ 195.428 Overpressure safety devices and provide opportunity for harvest of the
overfill protection systems. ■ 41. In § 195.505 paragraph (i) is 2015 total allowable catch of pollock,
* * * * * revised to read as follows: consistent with the goals and objectives
(c) Aboveground breakout tanks that of the Fishery Management Plan for
are constructed or significantly altered § 195.505 Qualification program. Groundfish of the Bering Sea and
according to API Std 2510 (incorporated * * * * * Aleutian Islands Management Area.
by reference, see § 195.3) after October (i) After December 16, 2004, notify the DATES: Effective 1200 hrs, Alaska local
2, 2000, must have an overfill protection Administrator or a state agency time (A.l.t.), March 11, 2015 through
system installed according to API Std participating under 49 U.S.C. Chapter 2400 hrs, A.l.t., December 31, 2015.
2510, section 7.1.2. Other aboveground 601 if the operator significantly FOR FURTHER INFORMATION CONTACT:
breakout tanks with 600 gallons (2271 modifies the program after the Steve Whitney, 907–586–7228.
liters) or more of storage capacity that administrator or state agency has
are constructed or significantly altered SUPPLEMENTARY INFORMATION: NMFS
verified that it complies with this manages the groundfish fishery in the
after October 2, 2000, must have an section. Notifications to PHMSA may be
overfill protection system installed BSAI exclusive economic zone
submitted by electronic mail to according to the Fishery Management
according to API RP 2350 (incorporated InformationResourcesManager@dot.gov,
by reference, see § 195.3). However, an Plan for Groundfish of the Bering Sea
or by mail to ATTN: Information and Aleutian Islands Management Area
operator need not comply with any part Resources Manager DOT/PHMSA/OPS,
of API RP 2350 for a particular breakout (FMP) prepared by the North Pacific
East Building, 2nd Floor, E22–321, New Fishery Management Council (Council)
tank if the operator describes in the Jersey Avenue SE., Washington, DC
manual required by § 195.402 why under authority of the Magnuson-
20590. Stevens Fishery Conservation and
compliance with that part is not
necessary for safety of the tank. ■ 42. Section 195.571 is revised to read Management Act. Regulations governing
as follows: fishing by U.S. vessels in accordance
* * * * *
with the FMP appear at subpart H of 50
■ 40. In § 195.452, paragraph (h)(4)(i)
§ 195.571 What criteria must I use to CFR part 600 and 50 CFR part 679.
introductory text and paragraph (m) are
determine the adequacy of cathodic In the Aleutian Islands subarea, the
revised to read as follows: protection? portion of the 2015 pollock total
§ 195.452 Pipeline integrity management in Cathodic protection required by this allowable catch (TAC) allocated to the
high consequence areas.
subpart must comply with one or more Community Development Quota (CDQ)
* * * * * of the applicable criteria and other directed fishing allowance (DFA) is
(h) * * * considerations for cathodic protection 1,900 metric tons (mt) as established by
(4) * * * contained paragraphs 6.2.2, 6.2.3, 6.2.4, the final 2015 and 2016 harvest
(i) Immediate repair conditions. An specifications for groundfish in the
6.2.5 and 6.3 in NACE SP 0169
operator’s evaluation and remediation BSAI (80 FR 11919, March 5, 2015).
(incorporated by reference, see § 195.3).
schedule must provide for immediate As of March 5, 2015, the
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repair conditions. To maintain safety, an Issued in Washington, DC, on February 26, Administrator, Alaska Region, NMFS,
operator must temporarily reduce the 2015, under authority delegated in 49 CFR (Regional Administrator) has
operating pressure or shut down the 1.97. determined that 1,900 mt of pollock
pipeline until the operator completes Timothy P. Butters, CDQ DFA in the Aleutian Islands
the repair of these conditions. An Acting Administrator. subarea will not be harvested.
operator must calculate the temporary [FR Doc. 2015–04440 Filed 3–10–15; 8:45 am] Therefore, in accordance with
reduction in operating pressure using BILLING CODE 4910–60–P § 679.20(a)(5)(iii)(B)(4), NMFS
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Document Created: 2015-12-18 11:58:40
Document Modified: 2015-12-18 11:58:40
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration | |
| Section | Rules and Regulations | |
| Action | Final rule. | |
| Dates | The effective date of these amendments is October 1, 2015. Immediate compliance with these amendments is authorized. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of March 6, 2015. | |
| Contact | Kay McIver, Transportation Specialist, by telephone at 202-366-0113, or by electronic mail at [email protected] | |
| FR Citation | 80 FR 12762 | |
| RIN Number | 2137-AE59 | |
| CFR Citation | 49
CFR
191 49 CFR 192 49 CFR 195 | |
| CFR Associated | Pipeline Safety; Reporting; Recordkeeping Requirements; Fire Prevention; Incorporation by Reference; Pipeline Safety; Security Measures; Ammonia; Carbon Dioxide; Petroleum and Reporting and Recordkeeping Requirements |
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