[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]


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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.

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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 
<a href="/cdn-cgi/l/email-protection#157e746c3b78767c63706755717a613b727a63"><span class="__cf_email__" data-cfemail="bad1dbc394d7d9d3ccdfc8faded5ce94ddd5cc">[email protected]</span></a>.

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:
    <bullet> Leak Surveys for Type B Gathering Lines;
    <bullet> Qualifying Plastic Pipe Joiners;
    <bullet> Regulating the Transportation of Ethanol by Pipeline;
    <bullet> Transportation of Pipe;
    <bullet> Threading Copper Pipe;
    <bullet> Offshore Pipeline Condition Reports;
    <bullet> Alternative Maximum Allowable Operating Pressure (MAOP) 
Notifications;
    <bullet> National Pipeline Mapping System;
    <bullet> Welders vs. Welding Operators;
    <bullet> Components Fabricated by Welding; and
    <bullet> Editorial Amendments.
    The PACs recommended PHMSA adopt the following proposals with 
changes to the regulatory text:
    <bullet> Responsibility to Conduct Construction Inspections;
    <bullet> Mill Hydrostatic Tests for Pipe to Operate at Alternative 
MAOP;
    <bullet> Calculating Pressure Reductions for Hazardous Liquid 
Pipeline Integrity Anomalies; and
    <bullet> Testing Components other than Pipe Installed in Low-
Pressure Gas Pipelines.
    The PACs recommended that PHMSA not adopt the proposed changes to:
    <bullet> Limitation of Indirect Costs in State Grants; and
    <bullet> 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:
    <bullet> 15 from pipeline trade associations.
    <bullet> 17 from pipeline operators.
    <bullet> 3 from pipeline manufacturers.
    <bullet> 3 from states and municipalities.
    <bullet> 1 from a Federal source (the National Transportation 
Safety Board (NTSB)).
    <bullet> 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.
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    \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.
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    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:
    <bullet> The proposed rule will result in significant cost impact 
to operators;
    <bullet> 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;
    <bullet> 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;
    <bullet> The proposed language does not differentiate between an 
operator's employee and a contractor's employee;
    <bullet> PHMSA should clarify the meaning of ``person participating 
in the construction'' of a pipeline;
    <bullet> Inspection and new construction should be an Operator 
Qualification (OQ) task;
    <bullet> Prohibiting any ``person'' involved in the construction of 
a pipeline could be interpreted to prohibit any other municipal 
employee from performing inspection; and
    <bullet> 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:
    <bullet> PHMSA share any supporting information provided by NAPSR 
to show that leaks are the primary hazard for Type B gathering 
pipelines;
    <bullet> 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;
    <bullet> The docket contains no supporting evidence to show that 
the proposed amendment is based on facts and not speculation;
    <bullet> Excavation damage may pose a greater risk than leaks in 
Type B gathering lines;
    <bullet> PHMSA should develop estimates of the cost of compliance 
for affected operators;
    <bullet> The economic impact may exceed the threshold for a non-
significant regulatory action; and
    <bullet> 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 <a href="/cdn-cgi/l/email-protection#41082f272e332c2035282e2f1324322e34332224320c202f2026243301252e356f262e37"><span class="__cf_email__" data-cfemail="6821060e071a05091c0107063a0d1b071d1a0b0d1b250906090f0d1a280c071c460f071e">[email protected]</span></a> 
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 
<a href="/cdn-cgi/l/email-protection#3871565e574a55594c5157566a5d4b574d4a5b5d4b755956595f5d4a785c574c165f574e"><span class="__cf_email__" data-cfemail="0d44636b627f606c796462635f687e62787f6e687e406c636c6a687f4d696279236a627b">[email protected]</span></a>, 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 
<a href="/cdn-cgi/l/email-protection#11587f777e637c7065787e7f4374627e64637274625c707f7076746351757e653f767e67"><span class="__cf_email__" data-cfemail="652c0b030a170804110c0a0b3700160a101706001628040b0402001725010a114b020a13">[email protected]</span></a>; 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 <a href="/cdn-cgi/l/email-protection#4b02252d2439262a3f222425192e38243e39282e38062a252a2c2e390b2f243f652c243d"><span class="__cf_email__" data-cfemail="3e775058514c535f4a5751506c5b4d514b4c5d5b4d735f505f595b4c7e5a514a10595148">[email protected]</span></a>, 
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 
<a href="/cdn-cgi/l/email-protection#e6af888089948b87928f8988b48395899394858395ab878887818394a6828992c8818990"><span class="__cf_email__" data-cfemail="82cbece4edf0efe3f6ebedecd0e7f1edf7f0e1e7f1cfe3ece3e5e7f0c2e6edf6ace5edf4">[email protected]</span></a>; 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 
<a href="/cdn-cgi/l/email-protection#97def9f1f8e5faf6e3fef8f9c5f2e4f8e2e5f4f2e4daf6f9f6f0f2e5d7f3f8e3b9f0f8e1"><span class="__cf_email__" data-cfemail="88c1e6eee7fae5e9fce1e7e6daedfbe7fdfaebedfbc5e9e6e9efedfac8ece7fca6efe7fe">[email protected]</span></a>, 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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