# Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations

- **operation:** document
- **citation:** 80 FR 12762
- **title:** Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2015-03-11
- **effective on:** 2015-10-01
- **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 for both gas and hazardous liquid pipelines. Editorial changes are also included.
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- **source url:** https://www.federalregister.gov/documents/2015/03/11/2015-04440/pipeline-safety-miscellaneous-changes-to-pipeline-safety-regulations
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Federal Register, Volume 80 Issue 47 (Wednesday, March 11, 2015) [Federal Register Volume 80, Number 47 (Wednesday, March 11, 2015)] [Rules and Regulations] [Pages 12762-12781] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [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
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