
[Federal Register Volume 82, Number 13 (Monday, January 23, 2017)]
[Rules and Regulations]
[Pages 7972-8002]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-31461]



[[Page 7971]]

Vol. 82

Monday,

No. 13

January 23, 2017

Part III





Department of Transportation





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Pipeline and Hazardous Materials Safety Administration





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49 CFR Parts 190, 191, 192, 195, and 199





Pipeline Safety: Operator Qualification, Cost Recovery, Accident and 
Incident Notification, and Other Pipeline Safety Changes; Final Rule

  Federal Register / Vol. 82 , No. 13 / Monday, January 23, 2017 / 
Rules and Regulations  

[[Page 7972]]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 190, 191, 192, 195, and 199

[Docket No. PHMSA-2013-0163; Amdt. Nos. 190-19; 191-25; 192-123; 195-
101; 199-27]
RIN 2137-AE94


Pipeline Safety: Operator Qualification, Cost Recovery, Accident 
and Incident Notification, and Other Pipeline Safety Changes

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 address 
requirements of the Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011 (2011 Act), and to update and clarify certain 
regulatory requirements. Among other provisions, PHMSA is adding a 
specific time frame for telephonic or electronic notifications of 
accidents and incidents and adding provisions for cost recovery for 
design reviews of certain new projects, for the renewal of expiring 
special permits, and setting out the process for requesting protection 
of confidential commercial information. PHMSA is also amending the drug 
and alcohol testing requirements, and incorporating consensus standards 
by reference for in-line inspection (ILI) and Stress Corrosion Cracking 
Direct Assessment (SCCDA).

DATES: This final rule is effective March 24, 2017. The incorporation 
by reference of certain publications listed in the rule is approved by 
the Director of the Federal Register as of March 24, 2017.

ADDRESSES: U.S. Department of Transportation, Pipeline and Hazardous 
Materials Safety Administration, 1200 New Jersey Ave. SE., Washington, 
DC 20590.

FOR FURTHER INFORMATION CONTACT: Tewabe Asebe by telephone at 202-366-
5523, by email at Tewabe.Asebe@dot.gov, or by mail at U.S. Department 
of Transportation, Pipeline and Hazardous Materials Safety 
Administration, 1200 New Jersey Ave. SE., Washington, DC 20590.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Executive Summary
    A. Purpose of the Regulatory Action and Summary of the Major 
Provisions of the Regulatory Action in Question
    B. Costs and Benefits
II. Background
    A. Notice of Proposed Rulemaking
    B. Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011 and the National Transportation Safety Board Recommendations
    C. Summary of Each Topic Under Consideration
III. Pipeline Advisory Committee
IV. Analysis of Comments and PHMSA Response
    A. Accident and Incident Notification
    B. Cost Recovery for Design Reviews
    C. Operator Qualification Requirements and NTSB Recommendations 
Related to Control Room Staff Training
    D. Special Permit Renewal
    E. Farm Taps
    F. Reversal of Flow or Change in Product
    G. Pipeline Assessment Tools
    H. Post-Accident Drug and Alcohol Testing
    I. Information Made Available to the Public and Request for 
Protection of Confidential Commercial Information
    J. In Service Welding
    K. Availability of Standards Incorporated by Reference
V. Regulatory Notices
VI. Amendments to Parts 190, 191, 192, 195, and 199

I. Executive Summary

A. Purpose of the Regulatory Action and Summary of the Major Provisions 
of the Regulatory Action in Question

    The purpose of this rulemaking action is to strengthen the Federal 
pipeline safety regulations and to address sections 9 and 13 of the 
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 
(2011 Act). Public Law 112-90. The amendment associated with section 9 
of the 2011 Act limits the timeframe within which the operator must 
electronically or telephonically report notice of an accident or 
incident to within one hour of confirmed discovery of the event. PHMSA 
expects that quicker accident and incident reporting will lead to a 
safety benefit to the public, the environment, and limit property 
damage. The amendment associated with section 13 of the 2011 Act allows 
PHMSA to recover its costs for design review work PHMSA conducts on 
behalf of the operators, which will allow PHMSA to use its limited 
resources in protecting public safety. PHMSA is also providing a 
renewal procedure for expiring special permits, and is making other 
minor and administrative changes. This final rule does not include the 
Operator Qualification (OQ) requirements proposed under subpart N for 
natural gas pipelines and subpart G for hazardous liquid pipelines; 
however, PHMSA is proceeding with amendments to control room staff 
training requirements. PHMSA is delaying final action on the OQ 
proposals until a later date and fully expects to consider all the 
comments received and the recommendations of the Pipeline Advisory 
Committees related to those specific issues in a subsequent final rule 
published in the near future.
    The specific amendments codified by this final rule are listed in 
detail below:
     Specifying an operator's accident and incident reporting 
time to not later than one hour after confirmed discovery and requiring 
revision or confirmation of initial notification within 48 hours of the 
confirmed discovery of the accident or incident;
     Setting up a cost recovery fee structure for design review 
of new gas and hazardous liquid pipelines with either overall design 
and construction costs totaling at least $2,500,000,000 or that contain 
new and novel technologies;
     Addressing the National Transportation Safety Board's 
(NTSB) recommendation to clarify training requirements for control room 
personnel;
     Providing a renewal procedure for expiring special 
permits;
     Excluding farm taps from the requirements of the 
Distribution Integrity Management Program (DIMP) requirements while 
proposing safety requirements for the farm taps;
     Requiring pipeline operators to report to PHMSA a change 
in product (e.g., from liquid to gas, from crude oil to highly volatile 
liquids (HVL)) or a permanent reversal of flow that lasts more than 30 
days;
     Providing methods for assessment tool selection by 
incorporating consensus standards by reference in part 195 for stress 
corrosion cracking direct assessment (SCCDA) that were not developed 
when the Integrity Management (IM) regulations were issued;
     Requiring electronic reporting of drug and alcohol testing 
results in part 199;
     Modifying the criteria used to make decisions about 
conducting post-accident drug and alcohol tests and requiring operators 
to keep for at least 3 years a record of the reason why post-accident 
drug and alcohol tests were not conducted;
     Including the procedure to request protection for 
confidential commercial information submitted to PHMSA;
     Adding reference to appendix B of API 1104 related to in-
service welding in parts 192 and 195; and

[[Page 7973]]

     Amending minor editorial corrections.

B. Costs and Benefits

    PHMSA has estimated annual compliance costs at $0.6 million less 
savings to be realized from the removal of farm taps from the 
Distribution Integrity Management Program requirements. PHMSA could not 
quantify annual benefits as readily due to data limitations. However, 
the improvements to and the clarification of regulations, including 
those for post-incident investigations along with other provisions, are 
designed to reduce pipeline incidents and the associated consequences, 
including the potential to prevent a future high-consequence event, 
such as those that have occurred on gas transmission and hazardous 
liquid pipelines in the past.

II. Background

A. Notice of Proposed Rulemaking

    On July 10, 2015, PHMSA published a notice of proposed rulemaking 
(NPRM) to address requirements in the 2011 Act pertaining to accident 
and incident reporting (section 9) and cost recovery (section 13); to 
address certain National Transportation Safety Board (NTSB) 
recommendations made in response to the pipeline incidents in San Bruno 
CA,\1\ and Marshall, MI; \2\ and to update and clarify certain 
regulatory requirements. 80 FR 39916. Among other provisions, PHMSA 
proposed to add a specific time frame for telephonic or electronic 
notifications of accidents and incidents and to add provisions for cost 
recovery for design reviews of certain new projects, to add provisions 
for the renewal of expiring special permits, and to include the 
procedure for submitters of information to request PHMSA treat the 
information as confidential. Also, PHMSA proposed changes to the 
operator qualification (OQ) requirements and drug and alcohol testing 
requirements and proposed to incorporate consensus standards by 
reference for inline inspection (ILI) and Stress Corrosion Cracking 
Direct Assessment (SCCDA).
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    \1\ https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf.
    \2\ https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf.
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B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 
and the National Transportation Safety Board Recommendations

    The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 
2011 was signed into law by President Barack Obama on January 3, 2012. 
The 2011 Act was enacted in part to enhance safety and protect the 
environment during the transportation of products by pipeline. H. Rept. 
112-297. As discussed above, this rulemaking addresses two provisions 
from the 2011 Act:
     Section 9 requires PHMSA to specify a time limit for 
telephonic or electronic reporting of pipeline accidents and incidents
     Section 13, which is codified at 49 U.S.C. 60117(n), 
allows PHMSA to prescribe a fee structure and assessment methodology to 
recover costs associated with design and construction reviews
    This rule also addresses certain National Transportation Safety 
Board (NTSB) recommendations arising out of the September 9, 2010, San 
Bruno, CA, pipeline rupture of a natural gas line that killed eight 
people, and the July 25, 2010, pipeline rupture in Marshall, MI, that 
resulted in the release of an estimated 843,444 gallons of crude oil in 
a wetland. The specific NTSB recommendations addressed in this 
rulemaking action are:

 P-11-12 on drug and alcohol testing of employees whose 
performance either contributed to the accident or cannot be completely 
discounted as a contributing factor to the accident
 P-12-3 on assessment tools incorporation by reference in part 
195
 P-12-7 on team training of control center staff
 P-12-8 on extending operator qualification training 
requirements for all hazardous liquid and gas transmission control 
center staff involved in pipeline operational decisions

C. Summary of Each Topic Under Consideration

Accident and Incident Notification
    Section 9 of the 2011 Act directs PHMSA to require pipeline 
operators to provide notification at the earliest practicable moment 
following confirmed discovery of an accident or incident, not to exceed 
1 hour following the time of such confirmed discovery. PHMSA is 
amending the Federal pipeline safety regulations to require operators 
to provide telephonic or electronic notification of an accident or 
incident at the earliest practicable moment, including the amount of 
product loss, following confirmed discovery.
Cost Recovery for Design Reviews
    On cost recovery for design reviews, section 13 of the 2011 Act 
allows PHMSA to prescribe a fee structure and assessment methodology to 
recover costs associated with any project with design review and 
construction costs totaling at least $2,500,000,000 and for new or 
novel technologies or design, as determined by the Secretary. PHMSA is 
amending the Federal pipeline safety regulations to prescribe a fee 
structure and assessment methodology for recovering costs associated 
with design reviews of new gas and hazardous liquid pipelines with 
either overall design and construction costs totaling at least 
$2,500,000,000 or that contain new and novel technologies.
NTSB Recommendations on Control Room Center Staff
    PHMSA is addressing the NTSB recommendation to extend operator 
qualification requirements to control center staff involved in pipeline 
operational decisions (P-12-8) and to require team training for control 
center staff involved in pipeline operations similar to those used in 
other transportation modes (P-12-7).
Special Permit Renewal
    On special permit renewal, PHMSA is amending Sec.  190.341 of the 
Federal pipeline safety regulations to add procedures for renewing a 
special permit.
Farm Taps
    On farm taps, PHMSA is amending the Federal pipeline safety 
regulations in 49 CFR part 192 to add a new section, Sec.  192.740, to 
cover regulators and overpressure protection equipment for an 
individual service line that originates from a transmission, gathering, 
or production pipeline (i.e., a farm tap), and to revise Sec.  192.1003 
to exclude farm taps from the requirements of the Distribution 
Integrity Management Program (DIMP).
Reversal of Flow or Change in Product
    On reversal of flow or change in product, PHMSA is expanding the 
list of events in Sec. Sec.  191.22 and 195.64 that require electronic 
notification to include the reversal of flow of product or change in 
product in a mainline pipeline. PHMSA is requiring operators to notify 
PHMSA electronically no later than 60 days before there is a reversal 
of the flow of product through a pipeline or when there is a change in 
the product flowing through a pipeline. In addition, PHMSA is amending 
Sec. Sec.  192.14 and 195.5 to reflect the 60-day notification and to 
require operators to notify PHMSA when over 10 miles of pipeline is 
replaced.

[[Page 7974]]

Pipeline Assessment Tools
    On pipeline assessment tools, PHMSA is incorporating by reference 
the following consensus standards into 49 CFR part 195: API STD 1163, 
``In-Line Inspection Systems Qualification'' (April 2013); NACE SP0102-
2010 ``Standard Practice, Inline Inspection of Pipelines'' (revised 
March 13, 2010); NACE SP0204-2008 ``Standard Practice, Stress Corrosion 
Cracking (SCC) Direct Assessment Methodology'' (reaffirmed September 
18, 2008); and ANSI/ASNT ILI-PQ-2005, ``In-line Inspection Personnel 
Qualification and Certification'' (reapproved October 11, 2010). Also, 
PHMSA is allowing pipeline operators to conduct assessments using 
tethered or remote control tools not explicitly discussed in NACE 
SP0102-2010, provided the operators comply with applicable sections of 
NACE SP0102-2010.
    Incorporation of these consensus standards will assure better 
consistency, accuracy and quality in pipeline assessments conducted 
using ILI and SCCDA.
Standards for ILI
    When the part 195 IM requirements were issued, there were no 
consensus industry standards that addressed ILI. Since then the 
following standards have been published:
    1. In 2002, NACE International published the first consensus 
industry standard that specifically addressed ILI (NACE Recommended 
Practice RP0102, ``Inline Inspection of Pipelines''). NACE 
International revised this document in 2010 and republished it as a 
Standard Practice, SP0102. PHMSA expects that the consistency, 
accuracy, and quality of pipeline ILI will be improved by incorporating 
the NACE International 2010 standard into the regulations. PHMSA asked 
the Standards Developing Organizations to develop this and the other 
standards and PHMSA is now adopting them to bring consistency 
throughout the industry. These standards provide tables to improve tool 
selection. PHMSA is providing hazardous liquids pipeline operators 
choices of tools to assess their pipelines and; therefore, PHMSA does 
not believe that these tool selections incur additional costs to the 
pipeline operators. The NACE International standard applies to ``free 
swimming'' inspection tools that are carried down the pipeline by the 
transported fluid. It does not apply to tethered or remotely controlled 
ILI tools. While the usage of tethered or remotely controlled ILI tools 
is less prevalent than the usage of free swimming tools, some pipeline 
IM assessments have been conducted using these tools. PHMSA believes 
many of the provisions in the NACE International standard can be 
applied to tethered or remotely controlled ILI tools and; therefore, 
PHMSA is allowing the use of these tools provided they generally comply 
with applicable sections of the NACE standard. The NACE standards were 
reviewed by PHMSA experts, and they agree with the provisions in the 
standards. Many operators are already following those guidelines. Our 
inspection guides will provide further instructions when this final 
rule is implemented.
    2. In 2005, the ASNT published ANSI/ASNT ILI-PQ, ``In-line 
Inspection Personnel Qualification and Certification.'' The ASNT 
standard provides for qualification and certification requirements that 
are not addressed in part 195. In 2010 ASNT published ANSI/ASNT ILI-PQ 
with editorial changes. The incorporation of this standard into the 
Federal pipeline safety regulations will promote a higher level of 
safety by establishing consistent standards to qualify the equipment, 
people, processes, and software utilized by the ILI industry. This and 
the other standards are being used by many operators but not all. This 
rule will ensure that all operators use these standards. Overall cost 
will not change, because these consensus standards will help operators 
eliminate problems before they arise. SCCDA is a technique allowed for 
gas transmission pipelines but is not specifically addressed in Sec.  
195.452 although it is also applicable to hazardous liquid pipelines. 
This rulemaking action will allow HL operators to use the SCCDA 
technique and ASNT is one of them. The ASNT standard addresses in 
detail each of the following aspects, which are not currently addressed 
in the regulations:
     Requirements for written procedures.
     Personnel qualification levels.
     Education, training, and experience requirements.
     Training programs.
     Examinations (testing of personnel).
     Personnel certification and recertification.
     Personnel technical performance evaluations.
    3. In 2005, API published API STD 1163, ``In-Line Inspection 
Systems Qualification Standard.'' PHMSA proposed to incorporate the 
2005 API 1163 because at the time the notice of the rulemaking action 
was developed, the latest version of API 1163 was under development. 
PHMSA has evaluated the revisions made to the latest version of API 
1163 and determined that the changes are not significant. Therefore, 
PHMSA is adopting API STD 2013 into part 195.
    This Standard serves as an umbrella document that is to be used 
with and complements the NACE International and ASNT standards that are 
incorporated by reference in API STD 1163. The API standard is more 
comprehensive than the requirements currently in part 195. The 
incorporation of this standard into the Federal pipeline safety 
regulations will promote a higher level of safety by establishing a 
consistent methodology to qualify the equipment, people, processes, and 
software utilized by the ILI industry. The API standard addresses, in 
detail, each of the following aspects of ILI inspections:
     Systems qualification process.
     Personnel qualification.
     ILI system selection.
     Qualification of performance specifications.
     System operational validation.
     System results qualification.
     Reporting requirements.
     Quality management system.
Stress Corrosion Cracking (SCC) Direct Assessment
    4. NACE SP0204-2008 ``Stress Corrosion Cracking Direct 
Assessment.'' SCC is a degradation mechanism in which steel pipe 
develops closely spaced tight cracks through the combined action of 
corrosion and tensile stress (circumferential, residual, or applied). 
These cracks can grow or coalesce to affect the integrity of the 
pipeline. SCC is one of several threats that can impact pipeline 
integrity. IM regulations in part 195 require that pipeline operators 
assess covered pipe segments periodically to detect degradation from 
threats that their analyses have indicated could affect the segment. 
Not all covered segments are subject to an SCC threat, but for those 
that are, SCCDA is an assessment technique that can be used to address 
this threat.
    Part 195 presently includes no requirements applicable to the use 
of SCCDA. Experience has shown that pipelines can go through SCC 
degradation in areas where the surrounding soil has a pH near neutral 
(referred to as near-neutral SCC). NACE Standard Practice SP0204-2008 
addresses near-neutral SCC. In addition, the NACE International 
recommended practice provides technical guidelines and process 
requirements that are both more comprehensive and rigorous for 
conducting SCCDA than are provided by Sec.  192.929 or ASME/ANSI 
B31.8S.

[[Page 7975]]

    The NACE standard provides additional guidance as follows:
     The factors that are important in the formation of SCC on 
a pipeline and what data should be collected;
     Additional factors, such as existing corrosion, which 
could cause SCC to form;
     Comprehensive data collection guidelines, including the 
relative importance of each type of data;
     Requirements to conduct close interval surveys of cathodic 
protection or other aboveground surveys to supplement the data 
collected during pre-assessment;
     Ranking factors to consider for selecting excavation 
locations for both near-neutral and high pH SCC;
     Requirements on conducting direct examinations, including 
procedures for collecting environmental data, preparing the pipe 
surface for examination, and conducting Magnetic Particle Inspection 
(MPI) examinations of the pipe; and
     Post assessment analysis of results to determine SCCDA 
effectiveness and assure continual improvement.
    In general, NACE SP0204-2008 provides thorough and comprehensive 
guidelines for conducting SCCDA and is more comprehensive in scope than 
Appendix A3 of ASME/ANSI B31.8S. PHMSA believes that requiring the use 
of NACE SP0204-2008 will enhance the quality and consistency of SCCDA 
conducted under IM requirements.
    SCC has also been the subject of research and development (R&D) 
programs that have been funded in whole or in part by PHMSA in recent 
years. PHMSA reviewed the results of several R&D programs concerning 
SCC as part of its consideration of whether it was appropriate to 
incorporate the NACE standard into the regulations. Among the reports 
PHMSA reviewed was ``Development of Guidelines for Identification of 
SCC Sites and Estimation of Re-inspection Intervals for SCC Direct 
Assessment,'' published by Integrity Corrosion Consulting Ltd. in May 
2010.\3\ This report evaluated the results of numerous studies 
conducted since the 1960s regarding SCC. The report used the 
conclusions from the studies to identify a group of 109 guidelines that 
pipeline operators could use to help identify sites where SCC might 
occur and determine appropriate re-inspection intervals when SCC is 
found. The guidelines address both high-pH and near-neutral-pH 
conditions. This report noted that the information used in developing 
the NACE standard consisted primarily of empirical data gathered from 
operators examining pipeline field conditions and failures. In 
contrast, the studies examined by Integrity Corrosion Consulting were 
mechanistic studies, and their results serve to complement the 
information operators have gained through field experience. PHMSA's 
review of the guidelines in this report identified a number of areas 
not addressed in detail in the NACE standard. Accordingly, PHMSA has 
included additional factors in Sec.  195.588 that an operator must 
consider if the operator uses direct assessment to assess SCC.
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    \3\ https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=199.
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    PHMSA acknowledges that the NACE standard may not address all 
aspects of SCC management, but PHMSA considers it better to incorporate 
additional structured guidance that is available now rather than await 
future standards. There is continual improvement in technology to 
detect and address various SCC threats. Three different standards 
organizations are currently working to improve standards on SCC: ASME 
B31.8, NACE 204 and API 1160. PHMSA participates on these technical 
committees. As more knowledge is gained on other types of SCC, such as 
sulfide assisted SCC and when newer standards get published, PHMSA will 
consider adopting them.
    PHMSA is revising Sec.  195.588, which specifies requirements for 
the use of external corrosion direct assessment on hazardous liquid 
pipelines, to include reference to NACE SP0204-2008 for the conduct of 
SCCDA. The rule will not require that SCCDA assessments be conducted, 
but it will require that the NACE standard be followed if an operator 
elects to perform such assessments. PHMSA has included additional 
factors that an operator must consider to address these if the operator 
uses direct pipeline to assess SCC.
Post-Accident Drug and Alcohol Testing
    On electronic reporting of drug and alcohol testing results, PHMSA 
is requiring operators electronic reporting for anti-drug testing 
results required in Sec.  199.119 and alcohol testing results required 
in Sec.  199.229. PHMSA is modifying these regulations to specify that 
it will provide notice to operators in the PHMSA Portal.\4\
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    \4\ https://portal.phmsa.dot.gov/.
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    On post-accident drug and alcohol testing, PHMSA is modifying 
Sec. Sec.  199.105 and 199.225 by requiring drug testing of employees 
after an accident and to allow exemption from drug testing only when 
there is sufficient information that establishes the employee(s) had no 
role in the accident. Therefore, PHMSA is amending the post-accident 
drug testing regulation to require documentation of the decision and to 
keep the documentation for at least three years.
Information Made Available to the Public and Request for Protection of 
Confidential Commercial Information
    On information made available to the public and request for 
confidential treatment, PHMSA is including the procedure for requesting 
confidential treatment of confidential commercial information submitted 
to PHMSA.
In-Service Welding
    On in-service welding, PHMSA is revising Sec. Sec.  192.225, 
192.227, 195.214, and 195.222 to add reference to API 1104, Appendix B.

III. Advisory Committees Meeting

    On June 2, 2016, the Gas Pipeline Advisory Committee (GPAC) \5\ and 
the Liquid Pipeline Advisory Committee (LPAC) \6\ met jointly in 
Arlington, Virginia. The committees are statutorily mandated advisory 
committees that advise PHMSA on proposed gas pipeline or hazardous 
liquid pipeline safety standards and risk management principles. Both 
committees were established in accordance with the Federal Advisory 
Committee Act, 5 U.S.C. App., as amended, and 49 U.S.C. 60115. Each 
committee consists of 15 members, with membership evenly divided among 
the Federal and state governments, regulated industry, and general 
public. The committees advise PHMSA on the technical feasibility, 
reasonableness, practicability, and cost-effectiveness of each proposed 
pipeline safety standard.
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    \5\ Officially designated as the Technical Pipeline Safety 
Standards Committee.
    \6\ Officially designated as the Technical Hazardous Liquid 
Pipeline Safety Standards Committee.
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    During the meeting, the committees considered the NPRM that was 
proposed to: Address (1) section 9 of the 2011 Act that would require 
operators to electronically or telephonically report notice of an 
accident and incident not later than one hour after the confirmed 
discovery; (2) address section 13 of the 2011 Act that would allow 
PHMSA to recover its costs for design review work PHMSA would conduct 
on behalf of the operators, which would allow PHMSA to use its limited 
resources in protecting the public safety; (3) expand the existing 
Operator Qualification (OQ) scope to cover new construction and certain 
other currently uncovered tasks; (4) provide a renewal procedure for 
expiring special permits; (5) exclude

[[Page 7976]]

farm taps from the DIMP requirements and to amend part 192 to add a new 
section that prescribes inspection activities for pressure regulators 
and over-pressurization protection equipment on service lines that 
originate from transmission, gathering, or production pipelines; (6) 
incorporate by reference into 49 CFR part 195: API STD 1163, ``In-Line 
Inspection Systems Qualification Standard'' (August 2005); NACE 
Standard Practice SP0102-2010 ``Inline Inspection of Pipelines'' NACE 
SP0204-2008 ``Stress Corrosion Cracking Direct Assessment;'' and ANSI/
ASNT ILI-PQ-2010, ``In-line Inspection Personnel Qualification and 
Certification'' (2010); (7) modify Sec. Sec.  199.105 and 199.225 by 
requiring drug testing of employees after an accident and allowing 
exemption from drug testing only when there is sufficient information 
that establishes the employee(s) had no role in the accident, and 
requiring documentation of the decision not to perform drug testing and 
to keep the documentation for at least three years; (8) and include the 
procedure for requesting confidential treatment of information 
submitted to PHMSA and PHMSA's decision regarding the request.
    After discussion, both Committees separately voted unanimously to 
recommend PHMSA implement the NPRM with certain changes. Specifically, 
the Committees recommended as follows:

A. Accident and Incident Notification Reporting

    Some of the Gas Pipeline Advisory Committee members were concerned 
about the accuracy of reporting gas leak within one hour of confirmed 
discovery of the leak. After discussion the issue, the committee agreed 
to recommend removing the one-hour amount of product lost reporting 
requirement from where it was proposed in Sec.  191.5(b)(5) and moving 
the requirement to Sec.  191.5(c).
    Also, both committees discussed the definition for ``confirmed 
discovery'' and separately recommended revising the definition as 
follows:

    Confirmed Discovery: when it can be reasonably determined, based 
on information available to the operator at the time, that a 
reportable event has occurred, even if only based on a preliminary 
evaluation.
Responses to the Advisory Committees' Recommendations
    The committees' recommendation also addresses the public comments 
and, therefore, PHMSA accepts the recommended changes.

B. Cost Recovery of Design Review

    Both committees discussed the proposal and agreed to recommend 
revising the definition for ``new and novel technologies,'' as follows:

    New and novel technologies means any products, designs, 
materials, testing, construction, inspection, or operational 
procedures that are not addressed in 49 CFR parts 192, 193, or 195, 
due to technology or design advances and innovation for new 
construction. Technologies that are addressed in consensus standards 
that are incorporated by reference into Parts 192, 193, and 195 are 
not ``new or novel technologies.''
Responses to the Advisory Committees' Recommendations
    The committees' recommendation also addresses the public comments 
and, therefore, PHMSA accepts the recommended changes.
    Also, both committees recommended revising the proposed Sec.  
190.405 by removing the phrases ``permitting activities, purchasing, 
and right of way acquisition.'' This recommendation also addresses the 
public comments and, therefore, PHMSA accepts the recommended changes.

C. Operator Qualification Requirements

    During the meeting, the committees discussed provisions related to 
the operator qualification requirements proposed in the NPRM. PHMSA is 
delaying final action on the OQ proposals under subpart N for natural 
gas pipelines and subpart G for hazardous liquid pipelines until a 
later date and fully expects to consider all the comments received and 
the recommendations of the Pipeline Advisory Committees related to 
those specific issues in a subsequent final rule.

D. Special Permit Renewal

    Both committees recommended revising Sec.  190.341(d)(1) by 
replacing the word ``application'' with the phrase ``application or 
renewal,'' revising Sec.  190.341(f) to limit aerial photography of 
pipeline segments where special permits affect public safety such as a 
class location special permit that allows a less stringent design 
factor in a populated area and allow operators to submit a summary of 
inline inspection survey results with permit renewals, and revising 
Sec.  190.341(e) to clarify that special permit renewals must be 
submitted 180 days prior to the grant expiration.
Responses to the Advisory Committees' Recommendations
    These committees' recommendations also address the public comments 
and, therefore, PHMSA accepts the recommended changes.

E. Farm Tap

    The Gas Pipeline Technical Committee recommended revising Sec.  
192.740 to make the following changes: In (a) change ``originates 
from'' to ``directly connected to,'' and in (b) to add the phrase 
``(except rupture discs) after the phrase ``relief device.''
    Also, the Committee recommended revising Sec.  192.1003(b) to make 
the following change: Replace the phrase ``. . . a service line that 
originates directly from a transmission'' with ``. . . an individual 
service line directly connected to a transmission.''
Responses to the Advisory Committee's Recommendations
    The committee's recommendations also address the public comments 
and, therefore, PHMSA accepts the recommended changes.

F. Pipeline Assessment Tools

    The Liquid Pipeline Advisory Committee recommended adopting the 
section as published in the NPRM except with the latest API STD 1163, 
``In-Line Inspection Systems Qualification Standard'' (April 2013) 
version.
    Also, a member of the advisory committee asked whether an operator 
has the option to run the right tools in assessing for in-line 
inspection and stress corrosion cracking direct assessment.
Responses to the Advisory Committee's Recommendations
    The committee's recommendations also address the public comments 
and, therefore, PHMSA accepts the recommended changes.
    With regard to the comment on right tool selection, the very reason 
PHMSA is incorporating these consensus industry standards into the 
Federal pipeline safety regulations is to guide operators to use the 
right tools. Operators can select the right pipeline assessment tools 
from the incorporated industry standards. However, if operators decide 
to choose assessment tools that are not incorporated by reference, the 
operators must justify, with data, why the selected assessment tools 
are better suited for their pipelines than the incorporated industry 
standards. In selecting assessment tools, operators should analyze the 
goal and objectives of the inspection and match relevant facts known 
about the pipeline and expected anomalies with the capabilities and 
performance of an assessment tool. The selected

[[Page 7977]]

assessment tool should have accuracy and detection capabilities, 
detection sensitivity, and classification capability. In addition, the 
sizing accuracy should be sufficient enough to enable prioritization, 
the location accuracy should enable locating anomalies, and the 
requirements for defect assessment must be adequate for the expected 
defect assessment algorithm.

G. On Post-Accident Drug and Alcohol Testing

    Both committees recommended removing existing language at the end 
of Sec.  199.105(b)(1) that states ``. . .or because of the time 
between that performance and the accident, it is not likely that a drug 
test would reveal whether the performance was affected by drug use.''
    In addition, some advisory committee members requested for 
compliance period to address union agreement for the drug testing 
reporting.
Responses to the Advisory Committee's Recommendations
    The committees' recommendations address the public comments. PHMSA 
accepts the recommended deletion for Sec.  199.105(b). PHMSA is not 
requiring new recordkeeping in this rule. The only requirement is to 
keep records of decisions not to administer post-accident employee drug 
tests for at least 3 years.

H. Information Made Available to the Public and Request for 
Confidential Treatment

    Both committees recommended to make editorial changes, including 
the title of the section, to reflect the agency's goal in providing a 
procedure for confidential commercial information submitted to PHMSA.
Responses to the Advisory Committees' Recommendations
    The committees' recommendations also address the public comments 
and, therefore, PHMSA accepts the recommended changes.

IV. Summary and Response to Comments

    PHMSA received 35 comments on the proposed rule from the National 
Transportation Safety Board, Pipeline Safety Trust, pipeline trade 
associations, the Distribution Contractors Association, the ASME B31Q 
Qualification of Pipeline Personnel Technical Committee, the American 
Medical Review Officers and the Pipeline Testing Consortium, pipeline 
operators, pipeline safety consultants, and citizens.
General Comments
    Most of the pipeline operators' comments were in support of and 
similar to their trade associations; therefore, pipeline operators' 
comments similar to their associations are not summarized again in the 
specific comments. However, comments that were not addressed by the 
trade associations are summarized.

A. Accident and Incident Notification

1. PHMSA's Proposal
    PHMSA proposed to amend the Federal pipeline safety regulations to 
require operators to provide telephonic or electronic notification of 
an accident or incident at the earliest practicable moment, including 
the amount of product loss, following confirmed discovery. PHMSA 
proposed to define ``confirmed discovery'' as: Confirmed discovery 
means there is sufficient information to determine that a reportable 
event may have occurred even if an evaluation has not been completed.
2. Summary of Public Comment
Definitions (Sec. Sec.  191.3 and 195.2)
    PHMSA received comments from trade organizations, safety groups, 
government entities, and others stating the proposed definition for 
``confirmed discovery'' is confusing because it suggests that the 
operator has sufficient ``confirmed'' information that an event has 
occurred but also contains the phrase ``may have occurred.'' They 
believe ``sufficient confirmed information'' is an indication that a 
reportable or actual event has occurred, and the confirmed information 
should provide enough evidence of that event. Therefore, they urged 
PHMSA to revise the definition to remove ``may have'' and read ``. . . 
a reportable event has occurred.''
    Paiute Pipeline Company and Southwest Gas Corporation proposed 
adding a new term ``provisional discovery'' to mean that the operator 
has ``sufficient information to determine that an incident has likely 
occurred even if an evaluation has not been completed.'' They stated 
that this proposed change would address confusion with the proposed.
    The American Medical Review Officers and the Pipeline Testing 
Consortium commented that the definition for confirmed discovery is an 
incident/accident notification rather than a confirmation, since it is 
based only on ``sufficient information to determine that a reportable 
event may have occurred.'' They recommend that this term be replaced 
with ``accident notification,'' and later allowing the operator to 
``confirm the notification,'' rather than ``confirm the confirmed 
discovery.'' They also note that the terms incident, accident, and 
reportable event are used throughout the proposed changes, and they 
recommended using the single term ``accident'' in all of PHMSA's rules. 
The GPAC and the LPAC both recommended that PHMSA revise the definition 
of confirmed discovery as ``Confirmed Discovery: When it can be 
reasonably determined, based on information available to the operator 
at the time, that a reportable event has occurred, even if only based 
on a preliminary evaluation.''
Immediate Notice of Certain Incidents/Accidents (Sec. Sec.  191.5 and 
195.52)
    The NTSB and the Pipeline Safety Trust disagree with the proposed 
requirement to file a second NRC report within 48 hours to confirm 
initial incident or accident information, irrespective of whether there 
are changes to that information. They stated that allowing operators 48 
hours to file a follow-up report with more accurate information 
encourages operators to provide incomplete information initially and, 
instead, rely on the 48-hour second notification requirement to report 
more accurate incident data. They were concerned that this would delay 
receipt of information by the NTSB or other responding agencies that is 
needed to decide whether to mobilize a response.
    In addition, the NTSB suggested that the second notification 
requirement would be significantly improved if PHMSA established a 
follow-up reporting requirement that would be triggered only ``when the 
pipeline operator has confirmed that previously reported information 
has significantly changed,'' and that PHMSA should include guidance on 
what constitutes a ``significant change,'' emphasizing the number of 
injuries and fatalities, evacuation zone changes, release amount, 
environmental impact, and infrastructure and equipment damage. They 
also suggested PHMSA should establish a cutoff time starting with the 
time of the first notification, since the benefit of extending the 
reporting period beyond a 12-hour timeframe is negligible for NRC 
notifications and changes in response to decisions by notified 
organizations.
    The American Public Gas Association (APGA), the American Gas 
Association (AGA), and some pipeline operators commented operators 
cannot provide meaningful estimates of gas loss within one hour and 
recommended that the estimates should be included in the proposed 48-
hour update to the one-

[[Page 7978]]

hour notification. In addition, the AGA commented that the product loss 
requirement should be quantified at a loss of three million cubic feet 
or more. The Interstate Natural Gas Association of America (INGAA) and 
some pipeline operators suggested modifying the proposed language to 
include the ``initial estimate of amount of product loss, to the extent 
practicable.'' In addition, INGAA commented that PHMSA should not make 
the 48 hours reporting change effective until the NRC has the means to 
accept supplemental reports, that PHMSA should modify the definition of 
a ``reportable incident'' to only include significant events that 
include a sudden loss of pressure resulting in a large amount of gas 
released or a potential fatality or injury necessitating an in-patient 
hospitalization and only apply the one-hour timing to these significant 
events, and that PHMSA should extend the permissible timing for events 
requiring operators to report only on account of property damage 
estimates and minor leaks.
    The American Petroleum Institute and the Association of Oil Pipe 
Lines (API-AOPL) and some operators commented that for the 48-hour 
notification, PHMSA should clarify that an operator may revise the 
initial estimate made to the NRC to reflect a zero sum regarding the 
amount of product released and the number of fatalities and/or injuries 
in connection with an incident in the event that a notification is made 
in error.
    API-AOPL and some pipeline operators commented that calculating 
whether an incident is below the $50,000 threshold will be difficult 
within the one-hour time limit and that the cost threshold for 
notification should be eliminated. Magellan Midstream Partners 
commented that the $50,000 threshold should be removed, or as a 
reporting criterion it should be increased to $250,000 and a threshold 
volume of 100 barrels of released product. In addition, Magellan 
commented that PHMSA should consider expanding the reporting criteria 
to include the evacuation of residential or commercial properties and 
the closure of a transportation corridor such as a ship channel, 
railroad, state or federal highway, or city and county roads. If a 
threshold is retained at $50,000, Magellan recommended it should apply 
only to the cost of third party property damage, and not the expenses 
and cost of repairs to operator property.
    Energy Transfer Partners suggested that the title for Sec. Sec.  
191.5 and 195.52 be retitled using a more accurate descriptive word 
such as ``prompt'' or ``timely'' in place of ``immediate.''
    The GPAC proposed that PHMSA move the provision proposed in Sec.  
191.5(b)(5) addressing the amount of product lost to paragraph Sec.  
191.5(c).
3. PHMSA Response
    With regards to the definitions, including the Advisory Committees' 
recommended definitions, the term ``confirmed discovery'' is in the 
2011 Act and cannot be replaced by alternative terms. In addition, the 
terms ``incident'' and ``accident'' are in the 2011 Act, and replacing 
``incident'' by ``accident'' throughout the Federal pipeline safety 
regulations would be out of the scope of this rulemaking action.
    PHMSA proposed ``may have occurred'' in the definition of 
``confirmed discovery'' to abide by the Congressional mandate requiring 
operators to alert the NRC to accidents and incidents despite not 
having a complete assessment. The purpose of the notification is to 
alert local, state, and federal agencies with notification at the 
earliest practicable moment so that emergency personnel or 
investigators can be dispatched quickly to mitigate the consequences of 
such an event. Without this requirement, each operator may have a 
different methodology in its procedures when responding to an accident 
or incident that could potentially take hours or days before an 
operator has completed its evaluation and determined that an accident 
or incident had in fact occurred. If an operator were allowed to wait 
for a definitive confirmation, based upon the procedures it has in 
place to identify and report accidents and incidents, even if the 
operator has sufficient evidence through its employees or the public, 
the intent of the Congressional mandate would be defeated. To address 
the public comments and the Advisory Committees recommendations, PHMSA 
has revised the definition of ``confirmed discovery.''
    With regard to the immediate and secondary notifications, section 
9(b)(3) of the 2011 Act directs PHMSA to require owners and operators 
of pipelines to revise their initial telephonic or electronic notice to 
the Secretary and the NRC with an estimate of the amount of the product 
released, an estimate of the number of fatalities and injuries, if any, 
and any other information determined appropriate by the Secretary 
within 48 hours of the accident or incident, to the extent practicable. 
Therefore, PHMSA proposed these requirements based on the 2011 Act.
    With regard to operators updating their reporting to the NRC, PHMSA 
has no authority to require the NRC to update operators' initial 
reports without generating a new report. Section 9(c) of the 2011 Act 
directs the NRC to update the initial report without generating a new 
report. PHMSA contacted the NRC to find out how the mandate could be 
met, and the NRC informed PHMSA that it would require a substantial 
amount of funding for the Center to have this capability; however, the 
2011 Act does not allocate funding for this mandate.
    With regard to changing the reporting thresholds for both gas and 
hazardous liquid pipelines, the NPRM did not address them and they are 
out of scope of this rulemaking action.

B. Cost Recovery for Design Reviews

1. PHMSA's Proposal
    PHMSA proposed to amend the Federal pipeline safety regulations to 
prescribe a fee structure and assessment methodology for recovering 
costs associated with design reviews of new gas and hazardous liquid 
pipelines with design and construction costs totaling at least 
$2,500,000,000 or that contain new and novel technologies.
2. Summary of Public Comment
On Proposed Definition of ``New and Novel Technologies'' (Sec.  190.3)
    Many industry groups including API-AOPL commented that definition 
of ``new and novel'' is overly broad and a narrower definition should 
be provided in the final rule. The AGA and some pipeline operators 
commented that they are concerned that an operator would undergo an 
extensive documentation and submittal process and enter into a Master 
Agreement for cost recovery regardless of the scope and size of impact 
of the new or novel technology, and recommended specifying that the new 
and novel technology would be defined as requiring a special permit per 
49 U.S.C. 60118(c).
    INGAA and some pipeline operators also commented that the 
definition of ``new or novel technologies or design'' exceeds the 
intent of Congress' authorization because Congress only intended to 
authorize cost recovery for facility design reviews only and did not 
intend to authorize cost recovery for any potential review or 
inspection, including events occurring after design and construction 
are complete, such as the development of operational procedures or 
routine enforcement audits. These commenters note that conducting 
pipeline inspections or reviewing operational procedures

[[Page 7979]]

should not be included in the cost recovery methodology.
    Both Advisory Committees recommended revising the definition of new 
and novel technologies to mean ``any products, designs, materials, 
testing, construction, inspection, or operational procedures that are 
not addressed in 49 CFR parts 192, 193, or 195, due to technology or 
design advances and innovation for new construction. Technologies that 
are addressed in consensus standards that are incorporated by reference 
into parts 192, 193, and 195 are not `new or novel technologies.'''
On Applicability (Sec.  190.403)
    API-AOPL and Kinder Morgan requested clarification from PHMSA 
whether the $2,500,000,000 threshold only applies to regulated assets 
in a master project that contains both assets regulated by the 
Department of Transportation and non-Department of Transportation 
regulated assets within the total investment. In addition, they stated 
that the proposed monetary threshold should only include design, 
material, and construction costs, and that operator overhead costs 
(e.g., engineering, legal, right-of-way acquisition work) should be 
excluded from calculating the proposed threshold. Also, they requested 
that PHMSA modify the language proposed in Sec.  190.403(c) to 
reference the appropriate section of the pipeline safety regulations 
for each review or inspection activity PHMSA performs as part of any 
safety design review.
    Energy Transfer Partners asked if PHMSA intends for operators to 
make notification of all projects meeting the requirements, and 
commented that PHMSA should develop a process outside of a rulemaking 
whereby new and novel technologies can be expeditiously evaluated and 
broadly approved for use. Energy Transfer Partners also commented that 
it is not clear whether a single notification or multiple notifications 
are required. In addition, Energy Transfer Partners asked what PHMSA 
means by ``To the maximum extent practicable.''
    The Gas Processors Association (GPA) and FlexSteel commented that 
the proposed rule does not clarify whether identical new technology is 
reviewed once or multiple times, even if different operators would be 
able to use the technology at different times. They asked when 
technology and/or design are no longer considered ``new and novel.'' 
The GPA and FlexSteel requested that the provisions for ``new and novel 
technology or design,'' including the definition and applicable cost 
recovery sections, be deleted from the final rulemaking.
    Spectra Energy Partners commented that PHMSA should include 
additional language that would make it clear that technologies that are 
addressed in consensus standards and incorporated by reference are not 
``new or novel technologies.'' They also stated that the inclusion of 
``operational procedures'' in the definition goes beyond the authority 
granted PHMSA in the Act, and requested it be removed and provided 
revision to the proposed language.
On Notifications (Sec.  190.405)
    INGAA and Kinder Morgan commented that PHMSA should revise its 
proposal to commence design review when the operator submits notice of 
its proposal because many of the proposed trigger events occur too 
early in the construction process for a company to commit firmly to a 
project. Commenters stated that many of the documents PHMSA is asking 
an operator to submit for a design review are not actually available 
120 days prior to the proposed event, and that some of the listed 
documents predate receipt of a Federal Energy Regulatory Commission or 
other authorizing certificate. Commenters suggested that a notification 
date following a more certain trigger, such as the date that a Federal 
Energy Regulatory Commission certificate is received, would allow for 
timely review while ensuring that the document repository is adequately 
populated.
    Alyeska asked PHMSA to add language that provides an alternative to 
the 120-day period for unique situations and circumstances.
    TransCanada commented that the proposed requirements are 
inconsistent with the current, more general requirement (Sec. Sec.  
191.22(c)(1)(i) and 195.64(c)(1)(i)) to notify PHMSA at least 60 days 
``before the event occurs'' including construction, and that PHMSA 
should compare the proposed notification requirements to the current 
requirements as well as revisit or rescind the September 12, 2014, 
Advisory Bulletin concerning construction notifications to ensure 
consistency and clarity regarding both the triggering event for 
notification and the notification period.
    Spectra Energy and Texas Pipeline Association Partners commented 
that PHMSA's proposed definition of ``commencement of construction'' is 
overly broad, creating conflicts and making compliance impracticable.
    Both Advisory Committees recommended deleting the phrase 
``permitting activities, purchasing, and right of way acquisition'' 
from this section.
On Master Agreement (Sec.  190.407)
    Energy Transfer Partners commented that there seems to be a 
presupposition that PHMSA will review the project, and that PHMSA and 
the applicant will enter into a master agreement. This section should 
be conditional and only require such an agreement in cases where PHMSA 
decides to conduct a review and the project meets a criterion for cost 
recovery under Sec.  190.403. This section should also provide for the 
operator to have audit rights covering invoices and supporting 
documentation.
On the Sample Master Cost Recovery Agreement
    The AGA and some pipeline operators commented that the Master 
Agreement process should be reciprocal in nature, and PHMSA should be 
required to provide timely feedback and responses through contractual 
deadlines applicable to the agency with clearly defined expectations 
for both participants in the agreement. API-AOPL commented that 
alternatives should be available to an operator that objects to the 
timeframe proposed by PHMSA to complete the safety design review; and 
whether the sample master agreement is meant to be authoritative or is 
open to comment and suggested revisions from the industry.
    INGAA commented that PHMSA needs to revise its proposed cost 
recovery methodology by setting up a set fee schedule to put all 
regulated parties on notice of the projected costs and time involved in 
the review to help inform an operator's decision to use new technology 
and, therefore, seek agency design review and approval.
    INGAA commented that PHMSA should consider a firm end point for 
design cost reimbursement when the pipeline is in-service. INGAA went 
on to say that PHMSA should revise its Master Cost Recovery Agreement 
in paragraph A(1) by stating that the review period commences when the 
operator submits notice of its proposal and that the agency should 
include examples of the type of other costs included under this 
section. INGAA also states that PHMSA should revise the termination 
date referenced in paragraph E(10) of the sample Master Cost Recovery 
Agreement to state ``the earlier of the termination of the review or 
the date the project is in-service.'' INGAA commented that the 
regulated community must be able to determine the range of costs and 
time involved prior to committing to a project. INGAA went on to say, 
at a minimum, operators

[[Page 7980]]

must be aware of the maximum potential costs charged for a design 
review. Without this critical information, the operator cannot 
determine whether the costs and time for review make it feasible to 
continue with the project. If PHMSA moves forward with this proposal 
without modification, it would dissuade operators from using advances 
in design and technology.
    The GPA commented that the terms and conditions of the proposed 
Master Cost Recovery Agreement do not relate to activities related to 
the reach and validation of new or novel technology or design. The GPA 
commented that it does not believe it was PHMSA's intent, but requests 
that the language for the Master Cost Recovery Agreement be amended to 
clarify that any cost recovery will be limited to the actual cost of 
the project review, including only the personnel directly involved in 
the review. The GPA commented that the Agreement also lacks any 
deadlines or obligations for PHMSA to meet and therefore, any agreement 
that requires a payment to be made for services should include 
parameters to ensure the review is timely. The GPA states that this 
will ensure the proposal moves through the process in a prescribed time 
period as long as the operator delivers the materials and responses 
necessary for PHMSA to move forward.
    TransCanada commented that the Master Agreement does not state 
under what circumstances the agreement would end; the list of required 
provisions is a ``minimum'' list, and PHMSA should clarify what other 
provisions would be included in the future for specific projects and 
whether operators would be able to negotiate the inclusion or exclusion 
of any provisions, and asked how a Master Agreement would be 
implemented for projects with long development cycles.
On Fee Structure (Sec.  190.409)
    The AGA and some pipeline operators commented that in order for 
operators to properly plan and budget for the design review, there 
should be a defined maximum for cost recovery of each design review 
that is subject to modification by mutual agreement.
    Energy Transfer Partners commented that the described fee structure 
needs to be clear, complete and agreed upon between PHMSA and the 
operator from the outset. As written, it is not clear that the fee 
structure cannot be unilaterally modified during the period of the 
review.
On Billing and Payment (Sec.  190.411)
    Energy Transfer Partners commented that the operator must have the 
right to not only verify the calculations, but also audit the bases for 
the calculations--time and activity reports, expense receipts, et 
cetera--in much the same way the operator monitors and approves time, 
material and expense reimbursements to its own employees and 
contractors.
3. PHMSA Response
    With regard to comments on definition of ``new and novel'' being 
overly broad, PHMSA has revised the definition by adding ``for new 
construction.'' The revised definition reads as: ``New and novel 
technologies means any products, designs, materials, testing, 
construction, inspection, or operational procedures that are not 
addressed in 49 CFR parts 192, 193, or 195, due to technology or design 
advances and innovation for new construction. Technologies that are 
addressed in consensus standards that are incorporated by reference 
into parts 192, 193, and 195 are not `new or novel technologies.' '' 
This new definition also ensures that technologies are not reviewed 
multiple times.
    Procedure reviews of the design, materials used, testing, 
inspections of materials and construction, and start-up operational 
procedures are all a part of PHMSA's Code inspections for new 
construction. PHMSA believes that the new definition addresses the 
comments received. With regard to comments on whether the Master Cost 
Recovery Agreement process is reciprocal, PHMSA has included facility 
costs that are part of the normal tariff rate recovery process.
    Regarding comments that conducting pipeline inspections or 
reviewing operational procedures should not be included in the cost 
recovery methodology, PHMSA agrees for existing pipelines. However, 
conducting pipeline inspections or reviewing operational procedures are 
a main function of PHMSA inspections for new pipeline facilities. In 
most cases, pipelines of this cost magnitude ($2.5 billion) are in new 
geographical areas with new operational personnel. The time needed to 
conduct these inspections normally takes much more time and dedication 
of PHMSA inspection staff and, therefore, need to be included in the 
cost recovery methodology.
    With regard to comments from the Advisory Committees and other 
stakeholders regarding trigger events occurring too early in the 
construction process for a company to commit firmly to a project, PHMSA 
agrees that some of the proposed requirements need not be included and 
has modified Sec.  190.405 to exclude permitting activities, material 
purchasing, and the right of way acquisition from the notification 
requirement.
    With regard to the Master Cost Recovery Agreement not relating to 
activities related to the reach and validation of new or novel 
technology or design, the Master Cost Recovery Agreement detailed in 
Sec.  190.407 was provided as a sample and would be tailored to 
specific requests to recover PHMSA costs of personnel involved in the 
review of the new or novel technology.
    Also, the Advisory Committees recommendations agree with PHMSA's 
responses to the public comments.

C. Operator Qualification Requirements and NTSB Recommendations Related 
to Control Room Staff Training

1. PHMSA's Proposal
    PHMSA proposed to amend the Federal pipeline safety regulations in 
49 CFR parts 192 and 195 relative to operator qualification 
requirements, to cover new construction, add clarification for covered 
tasks, clarify training and documentation requirements, and add program 
effectiveness requirements for operators to gauge the effectiveness of 
the OQ programs. The amendments to the OQ regulation also extend OQ 
requirements to operators of Type A gathering lines in Class 2 
locations and Type B onshore gas gathering lines.
    The amendments also address the NTSB recommendations to extend 
operator qualification requirements to control center staff involved in 
pipeline operational decisions (P-12-8) and requirements for team 
training of control center staff involved in pipeline operations 
similar to those used in other transportation modes (P-12-7).
2. Public Comments and PHMSA's Response on Scope and Definitions 
(Sec. Sec.  192.801 and 195.501, and Sec. Sec.  192.803 and 195.503), 
Qualification Program (Sec. Sec.  192.805 and 195.505), Program 
Effectiveness (Sec. Sec.  192.807 and 195.507), and Recordkeeping 
(Sec. Sec.  192.809 and 195.509)
    PHMSA received several comments on the new scope of operator 
qualifications (OQ), its definitions, operator qualification programs, 
program effectiveness, and OQ recordkeeping. However, during the 
rulemaking process, a decision was reached to not move forward with

[[Page 7981]]

revised OQ requirements in order to further evaluate the costs and 
benefits of this issue. This decision had no bearing on the proposed 
regulations regarding control room team training requirements; the 
comments received on that issue, as well as PHMSA's response, are 
discussed below.
    Therefore, PHMSA is delaying final action on the provisions 
regarding (1) OQ scope and definitions as they were proposed at 
Sec. Sec.  192.801 and 192.803 under subpart N for the natural gas 
pipeline regulations and at Sec. Sec.  195.501 and 195.503 for subpart 
G for the hazardous liquid pipeline regulations, respectively; (2) 
qualification programs as they were proposed at Sec. Sec.  192.805 and 
195.505 for the natural gas pipeline regulations and the hazardous 
liquid pipeline regulations, respectively; (3) OQ program effectiveness 
as they were proposed at Sec. Sec.  192.807 and 195.507 for the natural 
gas pipeline regulations and the hazardous liquid pipeline regulations, 
respectively; and (4) OQ recordkeeping as they were proposed at 
Sec. Sec.  192.809 and 195.509 for the natural gas pipeline regulations 
and the hazardous liquid pipeline regulations, respectively.
    PHMSA notes that revised OQ requirements will be published in a 
subsequent final rule in the near future, and it will consider and 
discuss, at length, all of the comments received for each of the topic 
areas listed above along with the recommendations of the Pipeline 
Advisory Committees, in that final rulemaking.
3. Summary of Public Comment on Control Room Management (Sec. Sec.  
192.631 and 195.446)
    The NTSB commented that it accepts PHMSA's plan to codify the 
training guidance previously issued as an advisory bulletin and, 
therefore, agrees with the proposed changes related to operator 
qualifications.
    The AGA requested that PHMSA allow 12 months before the final rule 
becoming effective, and that in Sec.  192.631(h)(6) the operator should 
be allowed to determine who should be involved in the team training 
exercises and suggested edits to the proposed regulatory language 
accordingly. With regards to the proposed roles and responsibilities in 
Sec.  192.631(b)(5), it requested PHMSA clearly define what is meant by 
`direct' and `supersede' in context of interacting with a controller 
and provided suggested edits to the proposed language.
    API-AOPL requested that currently qualified workers should not be 
affected by this rule and, therefore, the workers should be re-
qualified at the next, regular requalification scheduled interval.
    Enterprise suggested that the proposed rule be modified to read as, 
``the roles and responsibilities of others that could provide 
operational direction or guidance when a controller is performing a 
specific action that falls under an operator's OQ program.'' In 
addition, Enterprise suggested a new subparagraph (h)(7) be included in 
Sec. Sec.  192.631 and 195.446 to include an approval process to 
address when a controller's decision is to be superseded.
    The GPA commented that there is disconnect between the stated 
intent in the preamble and the actual language of the proposed rule and 
that the language used to describe the intent and purpose of the change 
differs in a meaningful way. The GPA commented that the ``roles and 
responsibilities'' are already defined by the current provision of 
subpart (b) of the respective Code; therefore, establishing a strict 
list of those who can override a controller could potentially paralyze 
a controller in an abnormal, or emergency, situation, which no operator 
or agency wants. The proposed new training requirement for those 
potentially interacting with controllers is overly broad, which 
potentially results in extensive unintended consequences. In addition, 
a bullet states PHMSA is proposing to ``modify operator qualification 
requirements including addressing a NTSB recommendation to clarify OQ 
requirements for control rooms . . .'' However, there is no reference 
found in the OQ section of the proposed rules; therefore, PHMSA should 
issue a statement in the final rule that the changes made to control 
room management will not have an impact on an operator's future OQ 
program.
    Magellan commented that OQ requirements should focus on those that 
directly perform the duties of the control room operator because there 
is no discernible benefit or advantage of expanding OQ requirements to 
include others who do not directly perform the duties of the Control 
Room Operator. Also, the roles and responsible of others who have the 
authority to direct or supersede specific technical actions needs to be 
limited to direct line supervisor and management personnel--as proposed 
in Sec.  195.446(b)(5), the roles, responsibilities, and qualifications 
of ``others'' is overly broad.
    Midwest Energy Association commented that it supports the use of 
team training for control room training but the requirement should not 
be placed in the OQ section and should instead be located in the 
control room management Sec.  192.631.
    Northeast Gas Association commented that it does not agree with the 
scope for team training for control room emergency situations, and 
recommends that the operator should have the authority to determine 
which personnel types should be involved during team training. Also, 
PHMSA should confirm that team training is only required for personnel 
who interact with control center staff on an operational basis as 
opposed to personnel who interact with controllers on non-operational 
matters.
    Paiute Pipeline Company and Southwest Gas Corporation commented 
that the proposed rulemaking under Sec.  192.631(h)(6) is inconsistent 
with the NTSB safety recommendation P-12-7--the recommendation is 
specific and limited to control center staff during emergency 
conditions. Therefore, PHMSA should provide justification 
substantiating the need for the proposed changes in Sec.  
192.631(b)(5). Paiute Pipeline Company also asked PHMSA to clarify as 
to the meaning of ``specific technical actions of controllers.''
    Thomas Lael Services supports the changes and commented that at the 
end of Sec. Sec.  192.631(h)(6) and 195.446(h)(6), it would be more 
clear if PHMSA inserts a clarification sentence. It recommends the 
following, ``This training shall be included in the scope required by 
Subpart N in of this part'' for Sec.  192.631(h)(6), with a 
corresponding change to Sec.  195.446(h)(6) that references subpart G 
rather than subpart N.
    TransCanada commented that for operators to conduct control room 
team training and exercises to include controllers ``and other 
individuals who would reasonably be expected to interact with 
controllers'' goes beyond the NTSB's July 25, 2012, recommendation to 
PHMSA; the phrase ``reasonably be expected to interact with 
controllers'' is vague and ambiguous and, therefore, that training 
should be limited to ``control center personnel,'' including those with 
the authority to direct or supersede the specific technical actions of 
a controller.
    Vectren Energy Delivery of Indiana and Ohio commented that 
additional clarification is necessary for control room team training 
because it may involve numerous ``soft skills.''
    Mr. Warren Miller commented that training as related to covered 
tasks should be required for initial evaluation/qualification, when a 
covered task has changed substantially, when someone has contributed to 
an accident, or no longer qualifies due to operator qualification 
issues. PHMSA

[[Page 7982]]

should clarify the required training for contractor individuals 
performing covered tasks on an operator's pipeline facilities. In 
addition, training should be required for all evaluators to ensure that 
evaluations are performed on each individual measures (the required 
KSAs) for each covered task consistently. The training and criteria for 
evaluators should include tracking and measuring an evaluator's 
performance to ensure criteria and established training is effective. 
In addition, specific language should be added to ensure that an 
evaluator will only evaluate a single individual. Criteria should be 
added to establish guidelines on what past experience and training each 
evaluator has on the specific task or field to indicate the evaluator 
can evaluate an individual. In addition, PHMSA should require an audit 
program to ensure evaluators for both operator and contract personnel 
are performing the evaluations as required.
4. PHMSA Response on Control Room Management (Sec. Sec.  192.631 and 
195.446)
    As to whether the operator should be allowed to determine who 
should be involved in the team training exercises and suggested edits 
to the proposed regulatory language accordingly, it remains the 
responsibility of the operator to define the training and qualification 
requirements for personnel performing covered tasks on their pipeline 
facility. This includes the requirement for operators to define 
personnel involved in team training exercises.
    As to the comment that currently qualified workers should not be 
required to requalify solely as a result of promulgation of the 
proposed rule, the control room management establishes the need for 
certain procedures and operating practices that would need to be 
incorporated into an operator's qualification program. If the prior 
qualification includes and meets all applicable requirements of the 
control room management plan and associated activities, the individual 
in question does not need to requalify. The rule does not specify that 
individuals performing covered tasks would need to be requalified 
solely as a result of this rulemaking action.
    As to the suggestion that the terms ``direct'' and ``supersede'' in 
Sec. Sec.  192.631(b)(5) and 192.446(b)(5) of the proposed rule be 
clearly defined, and to comments that these sections be ``modified,'' 
if field operations employee and supporting engineers who provide 
information or general advice to a controller are considered 
``directing'' a controller on a specific action as suggested by the 
commenters, then these individuals are directing and superseding the 
controller's authority. In addition, while the control room management 
regulations call out certain specific individuals such as controllers, 
supervisors, and field personnel, understanding of the requirements of 
control room management and appropriate training is essential for other 
individuals that interact with controllers, particularly those that may 
affect the ability of a controller to safely monitor and control the 
pipeline during normal, abnormal, and emergency situations. Other 
individuals to which team training might pertain likely vary by 
operator and control room depending on specific procedures and roles in 
the control room, but they could include individuals such as technical 
advisors, engineers, leak detection analysts, and on-call support. 
These individuals are typically already trained in their specific job 
function and have some awareness of the roles and responsibilities of 
controllers. In many cases, they are also included in discussions or 
meetings that involve control room personnel. However, these 
individuals may not always get together to be trained on how to work 
together as a team. Therefore, to provide for a controller's prompt and 
appropriate response to operating conditions, an operator must define 
the roles, responsibilities and qualifications of others with the 
authority to direct or supersede the specific technical actions of a 
controller.
    As to the suggestion that a new subparagraph (h)(7) be included in 
Sec. Sec.  192.631 and 195.446 to include an approval process to 
address when a Controller's decision is to be superseded, because this 
was not proposed, it is out of the scope of the final rule.
    As to the comment that PHMSA should issue a statement in the final 
rule that the changes made to control room management will not have an 
impact on an operator's future OQ program, additional requirements have 
been added to the control room management regulation to address the 
NTSB recommendation, including training. The OQ requirements prescribe 
the minimum requirements for operator qualification of individuals 
performing covered tasks on a pipeline facility, and include training.
    As to the comment that OQ requirements should focus on those that 
directly perform the duties of the control room operator because there 
is no discernible benefit or advantage of expanding OQ requirements to 
include others who do not directly perform the duties of the control 
room operator, issues identified from Marshall (for hazardous liquid) 
and to an extent San Bruno (for gas) in the NTSB report seem to 
disagree. Also, the OQ requirements prescribe the minimum requirements 
for operator qualification of individuals performing covered tasks on a 
pipeline facility. It remains the responsibility of the operator to 
identify covered tasks.
    As to the comment that the requirement should not be placed in the 
OQ section and should instead be located in the control room management 
Sec.  192.631, team training is under Sec.  192.631. It remains the 
responsibility of the operator to define the training and qualification 
requirements for personnel performing covered tasks on its pipeline 
facility. It is up to the operator as to how it documents the 
processes/procedures and records associated with this requirement.
    As to the comment that the operator should have the authority to 
determine which personnel types should be involved during team 
training, it remains the responsibility of the operator to define the 
training and qualification requirements for personnel performing 
covered tasks on their pipeline facility. Team training might vary by 
operator and control room depending on specific procedures and roles in 
the control room.
    As to the comment that team training is only required for personnel 
who interact with control center staff on an operational basis as 
opposed to personnel who interact with controllers on non-operational 
matters, while this may be true for some situations, some scenarios 
where non-operational type personnel/matters may need to be included. 
However, it is up to the operator to define who exactly is included and 
with ultimate determination of adequacy up to the inspector.
    As to the comment that the proposed rulemaking under Sec.  
192.631(h)(6) is inconsistent with the NTSB safety recommendation P-12-
7 because the recommendation is specific and limited to control center 
staff during emergency conditions and, therefore, PHMSA should provide 
justification substantiating the need for the proposed changes in Sec.  
192.631(b)(5) and clarify as to the meaning of ``specific technical 
actions of controllers,'' the NTSB recommendation is not specific to 
emergency conditions only. The recommendation as written is more 
generic to pipeline operations in general.
    As to the comment that at the end of Sec. Sec.  192.631(h)(6) and 
195.446(h)(6) PHMSA should insert a clarification

[[Page 7983]]

sentence referencing Subpart N in part 192 and Subpart G in part 195, 
it remains the responsibility of the operator to define the training 
and qualification requirements for personnel performing covered tasks 
on their pipeline facility, to include those performing control rooms 
related covered tasks. All operators are required to implement the OQ 
regulations per subpart N in part 192 and subpart G in part 195.
    Regarding comments on control room team training and exercises to 
include controllers, PHMSA disagrees that this section is ambiguous and 
goes beyond the NTSB recommendation. For example, leak detection 
analysts that were raised as an issue in the NTSB report on Marshall 
might not be considered control center personnel by a number of 
operators.
    As to the comment that additional clarification is necessary for 
control room team training because it may involve numerous ``soft 
skills,'' PHMSA will provide guidance in a separate document.
    As to the comment that training as related to covered tasks should 
be required for initial evaluation/qualification, when a covered task 
has changed substantially, when someone has contributed to an accident, 
or no longer qualified due to operator qualification issues, it remains 
the responsibility of the operator to define the training and 
qualification requirements for personnel performing covered tasks on 
their pipeline facility.
    As to the comment that PHMSA should clarify the required training 
for contractor individuals performing covered tasks on an operator's 
pipeline facilities, contractors face different OQ requirements. It is 
correct to say that contractors working for multiple pipeline operators 
may face multiple, and sometimes conflicting, requirements. This is why 
it is essential for each pipeline operator to have and effectively 
implement his/her own unique OQ program. Operator qualification 
programs must be specific to a pipeline operator and the covered tasks 
performed on the operator's facilities, taking into consideration the 
operator's methods of construction, operation, maintenance, and 
emergency response along with its unique tasks, equipment, and 
technologies utilized.
    In addition, the Advisory Committees recommended editorial changes 
to Sec. Sec.  192.631(h)(6) and 195.446(h)(6). PHMSA accepts the 
editorial changes and made the recommended changes accordingly.

D. Special Permit Renewal

1. PHMSA's Proposal
    PHMSA proposed to amend Sec.  190.341 of the Federal pipeline 
safety regulations to add procedures for renewing a special permit.
2. Summary of Public Comment
    The Pipeline Safety Trust clarified that any renewal applications 
will be treated the same as current initial applications in that they 
will be public, published on the PHMSA Web site, and subject to NEPA, 
and therefore suggested revising Sec.  190.341(d)(1) by replacing the 
word ``application'' with ``application or renewal.''
    The AGA commented that the proposed language in Sec.  190.341(e) is 
ambiguous and unclear as to its purpose and asked PHMSA to revise it.
    INGAA and Spectra Energy Partners commented that PHMSA should 
reexamine the extent of the documentation it requires as part of the 
renewal process and should collect summaries of reports and high-level 
maps rather than more extensive records.
    Energy Transfer Partners objected to the addition of the phrase 
``for a period of time from the date granted'' in Sec.  190.341(d)(2). 
They also objected to the proposed renewal process itself, described in 
Sec.  190.341(f), as overly burdensome, duplicative and unnecessarily 
repetitive in the amount and nature of the material required, and noted 
that requiring additional aerial photography rather than depicting the 
requested boundaries and features on the operator's GIS background is 
not necessary.
    FlexSteel commented that to be subject to the expiration or 
revocation without unjust reasons or adding additional stipulations 
after a special permit is approved jeopardizes the feasibility of the 
situation, or solution being sought by the operator. They requested 
that PHMSA should only review the special permit to confirm 
satisfactory performance by permitting continued pipeline operation and 
questioned why the request for renewal should be incumbent on the 
operator and require resubmittal of the information from the original 
request.
    The requested information should be limited to class location and 
high consequence area information in tabular format; the ILI 
requirement should be changed to the most recent information; data 
integration drawings should not be required as part of the special 
permit renewal request; and aerial photography data would not provide 
any meaningful information and be deleted from the requirement.
    Both Advisory Committees recommended PHMSA clarify that special 
permit renewals must be submitted 180 days prior to the grant 
expiration, limit aerial photography of pipeline segments where special 
permits affect public safety such as a class location special permit 
that allows a less stringent design factor in a populated area and 
allow operators to submit a summary of inline inspection survey results 
with permit renewals, and amend the language in in Sec.  190.341(d)(1) 
by replacing the word ``application'' with the phrase ``application or 
renewal.''
3. PHMSA Response
    PHMSA agrees that renewal applications should be treated the same 
as current initial applications in that they will be public, published 
on the PHMSA Web site, subject to NEPA, and published for comments on 
the Federal Register. Therefore, PHMSA revised the amendatory language 
in Sec.  190.341(d)(1) by replacing the word ``application'' with 
``application or renewal.''
    With regard to PHMSA reexamining the extent of the documentation it 
requires as part of the renewal process, Sec.  190.341(c) already has 
documentation requirements for special permit requests. PHMSA is 
requiring identical documentation for special permit renewal requests, 
too. PHMSA performs extensive technical analysis on special permit 
applications and typically conditions a grant of a special permit on 
the performance of alternative measures that would provide an equal or 
greater level of safety. PHMSA asks for summary information for 
operational, maintenance, and integrity conditions in the special 
permit.
    With regard to aerial photography data requirement, PHMSA agrees 
with commenters and will require aerial photography of pipeline 
segments where special permits affect public safety, such as a class 
location special permit that allows a less stringent design factor in a 
populated area.
    With regard to the comment that PHMSA should only review the 
special permit to confirm satisfactory performance by permitting 
continued pipeline operation, PHMSA's special permit renewals are a 
process to ensure the special permit conditions are being implemented 
and that the conditions continue to be suitable for pipeline safety, 
environmental protection, and in the public safety interest. Therefore, 
a requirement for renewal of special permits is necessary.

[[Page 7984]]

    PHMSA made the following changes to the proposed amendatory 
language in response to the comments: In Sec.  190.341(e)(1) no 
submittal date was provided. Therefore, the section is revised to make 
it clear that a special permit renewal must be submitted 180 days prior 
to the grant expiration. Also, in Sec.  190.341(f)(1)(v)(F), the 
proposed language required ILI survey results. That language is revised 
to allow only a summary of the most recent ILI survey results to be 
submitted with the permit renewal.
    Regarding the expiration requirement, the renewal process in Sec.  
190.341(f)(2) allows PHMSA to request additional operational, integrity 
or environmental information as needed to evaluate the special permit 
renewal. Also, PHMSA has the right to determine the period of time from 
the date granted to require renewal of the special permit to assure 
safety, environmental protection, and public interest. The safety needs 
for permit renewal time intervals will vary based upon the permit type, 
whether material, design factor, construction or operational.
    The Advisory Committees agreed with PHMSA's responses to the public 
comments.

E. Farm Taps

1. PHMSA's Proposal
    PHMSA proposed to amends the Federal pipeline safety regulations in 
49 CFR part 192 to add a new Sec.  192.740 to cover regulators and 
overpressure protection equipment for an individual service line that 
originates from a transmission, gathering, or production pipeline 
(i.e., a farm tap), and to revise Sec.  192.1003 to exclude farm taps 
from the requirements of the Distribution Integrity Management Program 
(DIMP).
2. Summary of Public Comment
    The AGA cautioned PHMSA that the agency's current position that 
``threats to typical farm taps are limited, and most are already 
addressed within part 192'' could be a slippery slope allowing for 
various assets within distribution systems to be exempt from DIMP 
simply because the risks are perceived as relatively low. The AGA 
commented that while this new proposed requirement may be appropriate 
for service lines not included in DIMP, it would be a redundant and 
cumbersome requirement for services lines whose risks are addressed 
holistically through integrity management.
    Similarly, INGAA commented that distribution operators will likely 
want to treat farm taps as part of their distribution system, and that 
operators that exclusively operate transmission pipelines will see no 
value in creating a distribution program just for the farm tap. 
Therefore, operators should have the option of treating a farm tap as 
either distribution or transmission as long as the necessary safety and 
reporting requirements are met.
    Operators NiSource, Inc., Northern Natural Gas Company, Southwest 
Gas Corporation, and TransCanada all agreed that PHMSA should allow an 
operator the option of keeping farm taps as part of its DIMP.
    CenterPoint Energy requested that PHMSA allow operators to 
establish their own inspection intervals or operating procedures based 
on the risks associated with particular types or classes of farm taps; 
they note that Sec.  192.740 is basically Sec.  192.739 and, therefore, 
Sec.  192.740 should include either the exemption or at the very least 
language including the limitation that an operator need only verify 
that a rupture disc with the correct range is installed at the 
location.
    DTE Gas Company commented that there still are threats and risks 
associated with farm tap service line piping between the farm tap 
regulator assembly and the customer, and that PHMSA should consider 
limiting the exception proposed in Sec.  192.1003(b) to the components 
of the farm tap regulator and valve assembly between the transmission, 
gathering, or production line and the service line pipe.
    The GPA commented that as drafted, Sec.  192.740(a) could be 
interpreted to exempt additional lines from the requirements of the 
section. The GPA also requested PHMSA clarify whether the proposal in 
Sec.  192.1003(b) applies to a service line that directly connects with 
an upstream production, gathering, or transmission pipeline. In 
addition, PHMSA should provide a five-year interval for inspection of 
farm taps.
    Kinder Morgan suggested that a farm tap be defined as ``a pipeline 
that maintains the same designation as the pipeline from which it 
originates (transmission, storage, gathering or production) and 
connects to a customer owned service line.'' They also requested that 
transmission gathering, or production pipeline operators should not be 
responsible for odorization unless it is currently provided as a 
service to the owner of the farm tap., and that the maintenance of any 
odorization along with pressure regulation, overpressure protection, or 
other facilities should be a ``grandfathered'' function and not a new 
requirement as part of the proposed rule.
    MidAmerican Energy Company commented that the added inspection 
requirements for ``farm taps'' are significantly more than what is 
currently required for inspection by DIMP, and that, as proposed by 
AGA, PHMSA should continue to allow those operators that want to 
address these services through DIMP or PHMSA should allow a 60-month 
inspection cycle due to the low risk potential. In addition, PHMSA 
should give consideration to removing or modifying the 60 psig 
requirement for pressure of services off of transmission mains for 
commercial/industrial customers.
    Texas Pipeline Association commented that it supports a revision to 
Sec.  192.1003 that states farm taps directly connected to upstream 
production, gathering, or transmission pipelines would be excluded from 
the DIMP requirements. Also, it supports the proposal in Sec.  192.740 
to require the inspection and testing of regulators and other over 
pressure protection equipment.
    Vectren Energy Delivery of Indiana and Ohio commented that in order 
to comply with the proposed rule, retrofits of farm taps would be 
required because the current standard for a High Pressure Service does 
not call for a block valve upstream of the pressure relief valve. The 
test and inspection of the set point of the device is not possible 
without removing the device or modifying the fabricated assembly. They 
also comment that the definition of a farm tap is not clear and that 
current risk models in DIMP result in additional accelerated actions 
for farm taps when elevated risk scores are noted. Therefore, PHMSA 
should allow farm taps to remain within DIMP and not mandate a 
prescribed inspection, or adjust the language in the proposed 
rulemaking to allow the operator the choice to leave them in DIMP or 
remove them from the DIMP and follow a mandated inspection frequency.
    The GPAC recommended that PHMSA amend the language defining farm 
taps to service lines ``directly connected to'' production, gathering, 
or transmission pipelines in both Sec. Sec.  192.740 and 192.1003(b). 
The committee also requested that rupture disks be exempted from relief 
devices required to be inspected.
3. PHMSA Response
    NAPSR originally requested the exclusion to exclude farm taps from 
the DIMP requirements, which PHMSA agrees with. Farm taps are single 
pipelines that deliver gas to a farmer or other landowner mostly in 
Class 1 locations, excluding them from the

[[Page 7985]]

DIMP requirements. However, these lines are still subject to inspection 
requirements for pressure regulating/limiting devices, relief devices, 
and automatic shutoff devices, which would provide adequate safety 
protection. Therefore, PHMSA is excluding farm taps from the DIMP 
requirements.
    Regarding comments asking that farm taps be regulated at the 
operators' choice--under DIMP or as proposed, uniform compliance 
requirements for farm taps are necessary to be enforceable. In 
addition, some comments requested that operators have the option of 
treating a farm tap as either distribution or transmission; however, 
farm taps are distribution service lines, and operators do not have the 
option to treat distribution service lines as transmission lines. 
However, this rule decreases the compliance burden for operators by 
excluding farm taps from the DIMP requirements. As to the inspection 
requirements for the farm tap safety devices, these safety devices are 
not new requirements for the safe operation. Therefore, these devices 
need to be inspected and maintained to ensure safe operation.
    With regard to comments for operators to establish their own 
inspection intervals, compliance cannot be effective if operators can 
choose their own inspection intervals because the requirements would be 
unenforceable. Inspection requirements are prescriptive regulations and 
are not intended to be risk-based or operator established inspection 
intervals. In addition, extending the inspection interval is not in the 
interest of safety, and PHMSA is keeping the interval as proposed at 
three years.
    Regarding comments that this section could be interpreted exempt 
additional lines from the requirements of the section, PHMSA revised 
the section to read ``any service line directly connected to a 
production, gathering, or transmission pipeline that is not operated as 
part of a distribution system.'' In addition, PHMSA has revised Sec.  
192.1003(b) to reflect the comment.
    Regarding comments that the definition of a farm tap is not clear, 
PHMSA did not propose a definition for a farm tap. A farm tap is a 
distribution service line. Regarding comments on grandfathering of 
odorization and other responsibilities, there is no grandfathering 
possible for something that has always been required, including 
requirements for odorizing distribution service lines.
    Regarding comment that that rupture disks be exempted from relief 
devices required to be inspected, PHMSA agrees with the commenter and 
rupture disks are exempt from the Sec.  192.740(b) requirement.
    The Gas Advisory Committee agreed with PHMSA's responses to the 
public comments.

F. Reversal of Flow or Change in Product

1. PHMSA's Proposal
    PHMSA proposed to expand the list of events in Sec. Sec.  191.22 
and 195.64 that require electronic notification to include the reversal 
of flow of product or change in product in a mainline pipeline. This 
notification is not required for pipeline systems already designed for 
bi-directional flow, or when the reversal is not expected to last for 
30 days or less. The proposal would require operators to notify PHMSA 
electronically no later than 60 days before there is a reversal of the 
flow of product through a pipeline and also when there is a change in 
the product flowing through a pipeline. Examples include, but may not 
be limited to, changing a transported product from liquid to gas, from 
crude oil to HVL, and vice versa. In addition, a modification is 
amended to Sec. Sec.  192.14 and 195.5 to reflect the 60-day 
notification and requiring operators to notify PHMSA when over 10 miles 
of pipeline is replaced because the replacement would be a major 
modification with safety impacts.
2. Summary of Public Comment
    API-AOPL requested a 30-day notice period in the final rule or 
flexibility for unforeseen events that necessitate extended or 
immediate reversals or product conversions. API-AOPL stated that PHMSA 
should clarify if an operator is required to report the reversal or 
product conversion 60 days prior to the event or 60 days prior to when 
the reversal or conversion work begins. API-AOPL also requested that 
PHMSA clarify whether or not the agency intended that operators may 
commence preparations for a reversal or conversion prior to making the 
proposed report to the agency. In addition, they requested the 
notification be required only prior to physical changes being made to 
the system, where business confidentiality agreements restrict the 
knowledge of such changes.
    INGAA commented that the proposed notification requirement should 
apply only to permanent flow reversals where an operator must change or 
modify its compressor facilities and related piping to accommodate a 
flow reversal, in which the pipeline needs the Federal Energy 
Regulatory Commission certificate authorization under the Natural Gas 
Act. For non-Federal Energy Regulatory Commission regulated pipelines, 
INGAA notes PHMSA would need to create another notification trigger. 
For non-bi-directional pipelines, the 60-day notification should be 
waived for an emergency or under unforeseeable circumstances.
    Alyeska noted that PHMSA proposed the addition of ``replacement'' 
to Sec.  195.64(c)(1)(ii), such that the regulation would require the 
60-day notification for ``construction of 10 or more miles of a new or 
replacement pipeline.'' PHMSA's guidance and advisory bulletin ADB-
2014-03 interprets the current Sec.  195.64(c)(1)(ii) as including 
replacement of 10 or more contiguous miles of line pipe in an existing 
pipeline, and Alyeska requested PHMSA add ``contiguous'' to the new 
proposed Sec.  195.64(c)(1)(ii) to reflect PHMSA's interpretation, so 
that multiple projects resulting in replacement of shorter pipeline 
segments that collectively add up to 10 or more miles are not 
considered subject to this rule.
    DTE Gas Company commented that the word ``product'' should not 
apply to gas pipelines as this term is normally associated with 
hazardous liquid lines in Sec.  191.22(iv). They also requested PHMSA 
consider excepting the notification requirement for pipelines operating 
in bi-directional flow modes in conjunction with storage field 
injection and withdrawal cycles.
    Enterprise commented that PHMSA should revise the notification 
requirement for ``reversal of flow or change in product'' to 30 days 
and provide an exception from the notification requirement for lines 
that have previously carried other commodities or that will not require 
significant modification to change product service. They also requested 
PHMSA include additional flexibility in the regulation to provide for 
emergency conditions that require reversals or product conversions 
where advance notice is not possible.
    The GPA suggested that a provision should be added to permit 
reporting in cases of unplanned or unanticipated reversals.
    Kinder Morgan commented that there are numerous instances where the 
new reporting criteria cannot be reasonably met for natural gas 
pipeline system, since the pipeline operating conditions are based upon 
varying customer demand and may change quickly due to such factors as 
weather changes, other pipeline outages or emergencies, and even 
changes in daily customer demand requirements. They requested that

[[Page 7986]]

changes in flow direction related to seasonal or customer demands and 
that last more than 30 days should be excluded from this reporting 
requirement. These flow direction changes have been routinely performed 
for many gas pipeline systems for a number of years and are a normal 
operating practice; due to the number of new sources of natural gas, 
pipeline operators that have the capability of reversing their flow 
direction must have the flexibility to meet these varying demands as 
they arise and would not be reasonably able to meet a 60-day reporting 
requirement.
    TransCanada requested that PHMSA re[hyphen]examine the September 
18, 2014, Advisory Bulletin and associated Guidance to Operators 
Regarding Flow Reversals, Product Changes and Conversion to Service to 
identify which requirements should be incorporated into the regulations 
then retire the September 18, 2014, Advisory Bulletin and Guidance.
3. PHMSA Response
    With regard to PHMSA allowing a 30-day notice period, for operators 
to reverse the flow of most existing pipelines requires many months of 
planning, facility modifications, pipeline pressure testing, and other 
repairs. Operators also have to go through the process of getting new 
tariffs through a rate case process, which takes a time interval that 
is longer than the 60 days. Therefore, PHMSA is keeping the 60-day 
notice period.
    With regard to PHMSA clarifying if an operator is required to 
report the reversal or product conversion 60 days prior to the event or 
60 days prior to when the reversal or conversion work begins and 
business confidentiality agreements restrict the knowledge of such 
changes, the new paragraph requires 60 days prior to the reversal 
event, and Sec.  190.23(c)(1)(i) already requires notification when 
costs are $10 million or over. With regard to notification requirement 
applying only to permanent flow reversals where the pipeline needs the 
FERC certificate authorization and for non-bi-directional pipelines for 
emergency or under unforeseeable circumstances, the flow reversal 
notification is for flow reversals over 30 days, unless an emergency 
event exists.
    With regard to multiple projects resulting in replacement of 
shorter pipeline segments that collectively add up to 10 or more miles, 
a pipeline with many segments and compressor stations that are being 
modified for flow reversal would be considered the same reversal 
project.
    Changes in flow direction that are related to seasonal or customer 
demands and last more than 30 days are not applicable to existing bi-
directional pipelines. This requirement is applicable for existing one 
direction pipelines that are modified for bi-directional or reverse 
flow.
    With regard to PHMSA's Advisory Bulletin and associated Guidance to 
Operators Regarding Flow Reversals, Product Changes and Conversion to 
Service dated September 18, 2014, the advisory bulletin is based upon 
49 CFR parts 192 and 195 and lessons-learned/findings from inspections 
of operator facilities for construction, operations, maintenance, and 
integrity management and, therefore, is still applicable.
    The Advisory Committees agreed with PHMSA's responses to the public 
comments.

G. Pipeline Assessment Tools

1. PHMSA's Proposal
    Section 195.452 of the pipeline safety regulations specifies 
requirements for assuring the integrity of pipeline segments where a 
hazardous liquid release could affect a high consequence area (referred 
to in this rule as ``covered segments''). Among other requirements, the 
regulations require that operators of covered segments conduct 
assessments, which consist of direct or indirect inspection of the 
pipelines, to detect evidence of degradation. Section 195.452(d) 
requires operators to conduct a baseline assessment of all covered 
segments. Section 195.452(j) requires that operators conduct 
assessments periodically thereafter.
    This rulemaking action incorporates by reference the following 
consensus standards into 49 CFR part 195: API STD 1163, ``In-Line 
Inspection Systems Qualification Standard'' (April 2013); NACE Standard 
Practice SP0102-2010 ``Inline Inspection of Pipelines'' NACE SP0204-
2008 ``Stress Corrosion Cracking Direct Assessment;'' and ANSI/ASNT 
ILI-PQ-2010, ``In-line Inspection Personnel Qualification and 
Certification'' (2010). Also, PHMSA allows pipeline operators to 
conduct assessments using tethered or remote control tools not 
explicitly discussed in NACE SP0102-2010, provided the operators comply 
with applicable sections of NACE SP0102-2010.
2. Summary of Public Comment
    The NTSB agreed that incorporating by reference the industry 
consensus standards listed in Section VII of the NPRM will improve 
operator pipeline assessment consistency, accuracy, and quality. 
Requiring a written SCCDA plan to include the pre-assessment as 
outlined in the NACE standard practice RP0204 would provide owner/
operators with valuable information and allow them to thoroughly assess 
vulnerabilities to stress corrosion cracking. Furthermore, the proposed 
requirement that the piping assessment plan contain a ``data gathering 
and integration'' element addressing the four, listed factors will 
further improve the SCCDA process. Also, the NTSB agreed that the NACE 
standard practice for conducting SCCDA combined with the written plan 
requirements are more comprehensive and rigorous than the current 
regulatory requirements.
    The AGA supports the incorporation of NACE SP0204-2008: Stress 
Corrosion Cracking (SCC) Direct Assessment Methodology by reference in 
pipeline safety regulations, but not with the additional proposed 
requirements to NACE SP0204-2008. The AGA contends that NACE SP0102-
2010 does not provide detailed procedures that are applicable in all 
situations on all pipelines and instead provides general 
recommendations. And that the ANSI/ASNT ILI-PQ-2010 should not be 
incorporated by reference in part 195 because it is not common practice 
for company personnel who may review data provided by vendors to comply 
with the qualifications outlined by this standard. The AGA does not 
support the proposed regulatory language in Sec.  195.591 because it 
removes the ability for operating personnel to use their engineering 
judgment when outlining the company's strategy for ILI.
    API-AOPL requested PHMSA to clarify any instances where the 
requirements outlined in SP0204-2008 are intended to serve as industry 
guidance. PHMSA's proposed incorporation of SP0204-2008 is a 
significant extension of the intent underlying the SCCDA data 
collection process. Therefore, PHMSA should clarify the inclusion of 
SP0204-2008, Table 2 in the data gathering process. They also requested 
PHMSA provide a technical justification for the proposed minimum number 
of excavations, as well as justification for incorporating API STD 1163 
(2005) when that standard has been updated recently. The proposal 
defining non-significant SCC in accordance with NACE SP0204-2008 is out 
of date and creates ambiguity both in terms of interpretation and 
enforcement; therefore, PHMSA should use the Canadian Energy Pipeline 
Association's (CEPA's) severity criteria, as it provides clear guidance 
on appropriate actions to address SCC

[[Page 7987]]

based on levels of SCC severity. For ILI tool standards proposed in 
Sec.  195.452, PHMSA should issue additional clarifying guidance 
reemphasizing the need to determine the appropriate assessment 
technology based on an evaluation of the segment specific risks 
associated with each portion of the line.
    Chevron Pipe Line Company commented that each proposed standard for 
incorporation by reference is supported by an array of associated 
material that is taken into consideration based on the many factors 
involved when assessing pipeline conditions, and therefore, PHMSA 
should provide adequate time beyond the comment deadline and before the 
final rule is issued for industry and regulatory stakeholders to 
adequately assess the proposal for feasibility.
    Energy Transfer Partners commented that in Sec.  195.452, regarding 
the capabilities of ILI tools, the operator should be able to choose 
tools that are appropriate for the threats identified or to obtain the 
data required, and it is understood that the operator needs to be able 
to justify such decisions. Energy Transfer Partners also commented that 
the mitigation requirements proposed in Sec.  195.588(c)(4)(ii) appear 
to be mandated with no technical basis and are contrary to much of the 
expert technical opinion on such testing. The stress level achieved 
during the ``spike'' portion of the hydrostatic test should be an 
engineered pressure defined by the operator to achieve some stated 
goal. The operator should be able to set that goal, and the 
corresponding pressure, to balance the various factors involved, 
including post-test operating pressure, retest interval and potential 
activation of otherwise stable anomalies. The duration of the ``spike'' 
portion of the test should likewise be engineered based upon similar 
factors. There is technical literature and technical opinion that, 
particularly at the very high pressures proposed by PHMSA, holding 
those pressures much beyond 5 minutes, and certainly beyond 10, 
provides no additional benefit. They comment that PHMSA has presented 
no basis or justification for a 30-minute hold, and that PHMSA has not 
presented a technical justification for the requirement of a subpart E 
hydrostatic test to be conducted as a continuation of the ``spike'' 
portion of the test. Properly engineered pressure testing can be an 
effective mitigation tool for stress corrosion cracking. However, a 
``one size fits all'' mandated approach to such testing is not 
appropriate and is not the most effective way of achieving effective 
mitigation and overall improvement in assurance of integrity. The 
pipeline operator should be responsible for determining the required 
testing parameters based upon the specifics of the line being tested 
and the established goal of the testing.
    Enterprise commented that with respect to the proposed ILI tools in 
Sec.  195.452(c) and (j), PHMSA should revise the proposal to clarify 
that a crack tool is not required for every ILI assessment or 
reassessment and clarify that operators need only consider the 
recommendations of the ILI consensus standards proposed to be 
incorporated by reference. They also commented that PHMSA should modify 
the proposed language similar to existing natural gas integrity 
management requirements in Sec.  192.921(a)(1). In addition, they 
requested Sec.  195.591 be clarified to state that operators need only 
``consider'' the recommendations in the proposed incorporation by 
reference standards, and that PHMSA should incorporate the most current 
version of API 1163 (2010), or risk inconsistency and/or conflict with 
NACE RP0102 because the 2005 API 1163 standard cross-references an 
older (2002) version of NACE RP0102, but PHMSA's proposed incorporation 
risks requiring actions that are inconsistent with the 2010 NACE 
version of that standard which is proposed to be incorporated by the 
regulation.
    Northeast Gas Association commented that it is concerned about 
additional requirements above and beyond NACE SP0204-2008 that are 
being proposed, such as PHMSA's proposal in Sec.  195.588(c)(1) to 
require gathering and evaluating data related to stress corrosion 
cracking at all sites an operator excavates during the conduct of its 
pipeline operations both within and outside covered segments.
    Thomas Lael Services provided suggested editorial comments for ILI 
of pipelines in proposed Sec.  195.591 and provided additional comments 
and new proposals into part 192.
    The LPAC recommended adopting the newer, April 2013 version of the 
API STD 1163, ``In-Line Inspection Systems Qualification Standard.''
3. PHMSA Response
    The additional requirements were generated by PHMSA subject matter 
experts based on their lessons learned from the integrity management 
program, and expert presentations of public workshops on stress 
corrosion cracking, risk, and new construction. PHMSA is incorporating 
API STD 1163 (April 2013); NACE Standard Practice SP0102-2010, NACE 
SP0204-2008, and ANSI/ASNT ILI-PQ-2010 into the regulations to provide 
clearer guidance for conducting integrity assessments with ILI. These 
standards complement each other, and they will promote a higher level 
of safety by establishing a consistent methodology to qualify the 
equipment, people, processes, and software utilized by the ILI 
industry.
    PHMSA is incorporating NACE SP0204-2008 into part 195 because it 
provides comprehensive, up-to-date guidelines on conducting SCCDA. It 
is more comprehensive in scope than Appendix A3 of ASME/ANSI B31.8S, 
and PHMSA has concluded the quality and consistency of SCCDA conducted 
under integrity management requirements would be improved by requiring 
the use of NACE SP0204-2008. The NACE standard provides additional 
guidance on: The factors that are important in the formation of stress 
corrosion cracking on a pipeline and what data should be collected; 
additional factors, such as existing corrosion, which could cause 
stress corrosion cracking to form; comprehensive data collection 
guidelines including the relative importance of each type of data; 
requirements to conduct close interval surveys of cathodic protection 
or other above-ground surveys to supplement the data collected during 
pre-assessment; ranking factors to consider for selecting excavation 
locations for both near neutral and high pH stress corrosion cracking; 
requirements on conducting direct examinations including procedures for 
collecting environmental data, preparing the pipe surface for 
examination, and conducting Magnetic Particle Inspection (MPI) 
examinations of the pipe; and post assessment analysis of results to 
determine SCCDA effectiveness and to assure continual improvement.
    PHMSA proposed to incorporate the 2005 API 1163 because at the time 
the notice of the rulemaking action was developed, the latest version 
of API 1163 was under development. PHMSA has evaluated the revisions 
made to the latest version of API 1163 and determined that the changes 
are not significant. Therefore, PHMSA is adopting API STD 2013 into 
part 195. However, adopting the Canadian Energy Pipeline Association's 
severity criteria is out of the scope of this rulemaking action.
    PHMSA provides adequate time for industry and regulatory 
stakeholders to adequately assess the proposal for feasibility. The 
agency goes through a long process of analyzing all comments, 
discussing summary of comments at the Advisory Committee meetings that 
are open to the public and getting their

[[Page 7988]]

recommendations and having internal review with PHMSA subject matter 
experts before issuing the final rule. PHMSA believes this process 
gives operators enough time to review the proposals.
    With regard to inspection tools selections, operators always have 
option of using their alternative to these standards as long as the 
alternative tools meet equivalency or exceed the provisions in these 
standards.
    If a pipeline includes legacy pipe or was constructed using legacy 
construction techniques, or the pipeline has experienced a reportable 
in-service accident since its most recent successful ``spike'' 
hydrostatic pressure test, due to an original manufacturing-related 
defect, a construction, installation, or fabrication-related defect, or 
a crack or crack-like defect, a spike pressure test would be required. 
Further, ongoing research and industry response to other PHMSA 
rulemaking actions is beginning to indicate that SCCDA is not as 
effective, and does not provide an equivalent understanding of pipe 
conditions with respect to stress corrosion cracking defects, as ILI or 
hydrostatic pressure testing at test pressures that exceed those test 
pressures (i.e., ``spike'' hydrostatic pressure test). Therefore, a 
``spike'' hydrostatic pressure test is well suited to address stress 
corrosion cracking and other cracking or crack-like defects.
    With regard to a crack tool not being required for every ILI 
assessment or reassessment and that operators need only consider the 
recommendations of the ILI consensus standards proposed to be 
incorporated by reference, operators always have the option to use 
their alternative to these standards as long as the alternative tools 
meet equivalency or exceed the provisions in these standards. These 
standards are incorporated in part 195 after lessons learned from past 
integrity management requirement in place for years; recent high 
profile incidents in Marshall, MI, San Bruno, CA, and Mayflower, AR, 
and recommendations from the NTSB to address crack like defects, stress 
corrosion cracking and seam corrosion issues, have indicated that 
current integrity management requirements do not address all anomalies 
in the pipeline. Further, PHMSA is revising Sec.  195.452(c)(1)(i)(A) 
to clarify the fact that operators should select the appropriate tool 
type to address the specific threats relative to their pipeline 
segments.
    The LPAC agreed with PHMSA's responses to the public comments.

H. Post-Accident Drug and Alcohol Testing

1. PHMSA's Proposal
    PHMSA is modifying Sec. Sec.  199.105 and 199.225 by allowing 
exemption from post-accident drug and alcohol testing only when there 
is sufficient information that establishes the employee(s) had no role 
in the accident.
    PHMSA's regulations required the documentation of decisions not to 
administer a post-accident alcohol test but the requirement to document 
decisions not to administer a post-accident drug test was only implied 
in the regulation, and the implied requirement is generally followed. 
PHMSA is amending the post-accident drug testing regulation to require 
documentation of the decision and to keep the documentation for at 
least three years.
2. Summary of Public Comment
    The NTSB commented that it believes the proposed change is 
responsive to its recommendation.
    The APGA commented that this requirement could be misinterpreted to 
require the operator to document actions of every utility employee 
after a reportable incident occurs. PHMSA uses the terms ``surviving 
covered employee'' and ``whose performance of a covered function'' to 
clarify that this proposed requirement only requires the operator to 
consider testing those employees who performed covered functions at the 
location of the incident either when the incident occurred or for some 
time period immediately prior to the incident; however, it does not 
require documentation for employees working elsewhere on the system. 
The APGA commented that it supports the proposed electronic submittal 
requirement for each annual management information system for the 
operator's drug and alcohol testing program.
    API-AOPL commented that the proposed rule for post-accident drug 
and alcohol testing does not discuss whether PHMSA has a specific 
process in mind for those operators requesting an exemption from the 
proposed test-reporting requirement and that PHMSA should clarify 
further on the process envisioned by the agency. Additionally, they 
requested PHMSA articulate whether it intends to create one 
standardized form to be used by all industry operators to document the 
decision to not administer a post-accident test, or whether individual 
operators will be required to generate their own forms.
    Enterprise commented that PHMSA should revise the post-accident 
drug and alcohol testing proposal to state affirmatively which 
employees must be tested under the regulations, and that PHMSA should 
generate a standard form to be used for decisions not to test, to avoid 
inconsistency both in application and reporting.
    The American Medical Review Officers and the Pipeline Testing 
Consortium recommended that in Sec. Sec.  199.105(b) and 199.225(a)(1) 
PHMSA use the same phrase ``contributed to the accident'' in the second 
sentence as was used in the first rather than the employee's ``role in 
the cause . . . of the accident.'' They also requested PHMSA remove the 
word ``severity'' in both sections because severity of any accident 
will vary, but does not affect whether a test is conducted. In 
addition, the discretion that an employer has in determining not to 
conduct a post-accident test ``because of the time between that 
performance and the accident, it is not likely that a drug test would 
reveal whether the performance was affected by drug use'' has been part 
of this section for years, but that makes it no less problematic. There 
are no scientifically acceptable criteria by which the employer could 
accurately make this decision; therefore, this option should be deleted 
from the employer's testing decision. Section 199.105(b)(2) requires 
documentation only on ``why the test was not promptly administered,'' 
but does not cover decisions made that eliminate some employees from 
testing all together. In contrast, Sec.  199.117(a)(5) only covers 
recordkeeping for ``decisions not to administer . . . the drug test,'' 
but does not cover why the employer could not accomplish the testing 
within 32 hours; therefore, each paragraph should add its missing part. 
This recommendation applies also to the alcohol section of the proposed 
rule, where Sec.  199.227(a)(2(i) and (b)(4) have the same issue. The 
proposed definition for ``covered task'' in Sec. Sec.  192.803 and 
195.503 runs the risk of being confused with ``covered function'' in 
Sec.  199.3; therefore, the term ``covered task,'' and its definition 
should be used in part 199 in lieu of ``covered function.'' In 
addition, they provided comments to other sections of part 199 that 
were not proposed in this rulemaking action.
    Thomas Lael Services commented that the documentation that 
describes why the decision not to test an individual relative to a 
reportable accident/incident should be kept for as long as the complete 
event records is kept.

[[Page 7989]]

    The Advisory Committees recommended deleting language from Sec.  
199.105(b), ``. . . or because of the time between that performance and 
the accident, it is not likely that a drug test would reveal whether 
the performance was affected by drug use.''
3. PHMSA Response
    Contrary to several commenters, this rulemaking does not establish 
new requirements for post-accident drug and alcohol testing. Those 
requirements currently exist in 49 CFR part 199. This rulemaking would 
modify the conditions under which an operator may decide not to test 
covered employees and establish a recordkeeping requirement for these 
decisions. Operators have been required to decide whether to post-
accident test covered employees since part 199 was promulgated. Each 
accident is unique. PHMSA can neither state affirmatively which 
employees must be tested nor create a template for making the decision 
about post-accident testing.
    An individual could ``contribute'' to an accident by causing it or 
by making the consequences more severe. The overall severity of the 
accident is irrelevant to the post-accident testing decision. The 
relevant question for severity is whether an employee's performance of 
a covered function affected the severity of the accident.
    In PHMSA's proposed Sec.  199.105(b)(2), operators would cease 
attempts to administer a drug test 32 hours after the accident. PHMSA 
concurs that ``or because of the time between that performance and the 
accident, it is not likely that a drug test would reveal whether the 
performance was affected by drug use'' should be removed from PHMSA's 
proposed 199.105(b)(1) and, therefore, the statement is removed.
    The new post-accident recordkeeping requirements merely specify the 
type of records and length of retention. Details about what must be in 
the records are contained in other sections of the regulations. The 
post-accident testing sections of the regulations clarify the contents 
of the records on decisions not to administer post-accident tests.
    Covered task is defined in parts 192 and 195. ``Covered function'' 
is defined in part 199 and has a meaning different from ``covered 
task.'' PHMSA used the term ``covered function'' appropriately in the 
NPRM.
    Since PHMSA has not established record retention criteria for 
accidents, the drug and alcohol testing regulations must establish the 
retention period for decisions not to administer post-accident tests.
    The Advisory Committees agreed with PHMSA's responses to the public 
comments.

I. Information Made Available to the Public and Request for Protection 
of Confidential Commercial Information

1. PHMSA's Proposal
    When information is submitted to PHMSA during a rulemaking 
proceeding, as part of an application for a special permit, or for any 
other reason, PHMSA may make that information publicly available. PHMSA 
does not currently set out in the pipeline safety regulations the steps 
for requesting protection of confidential commercial information. PHMSA 
has set out such a procedure in its hazardous materials safety 
regulations. Therefore, to inform the public of how to request 
protection of confidential business information submitted to the Office 
of Pipeline Safety and to provide information regarding PHMSA's 
decision, PHMSA is including the procedure in the pipeline regulations. 
If PHMSA were to receive a request for information marked as 
confidential or identifies a need to make the information publicly 
available, PHMSA will conduct a review of the information under the 
standards set forth in the Freedom of Information Act (FOIA), 5 U.S.C. 
552.
2. Summary of Public Comment
    The Pipeline Safety Trust asked that PHMSA include in Sec.  
190.343(b) the criteria by which PHMSA will make the decision about 
whether the information requested to be confidential will be removed 
from public availability and make clear whether that decision is an 
appealable administrative order.
    The American Gas Association (AGA) commented that it supported a 
clear path for operators to request confidentiality for submitted 
information, but indicated concern about PHMSA using its own judgment 
on when to keep that information confidential. AGA also suggested that 
operators should have an opportunity to classify their information 
related to special permits and thus their system as Sensitive Security 
Information.
    The American Petroleum Institute (API) and the Association of Oil 
Pipe Lines (AOPL) commented that they did not oppose the proposal, but 
requested that certain clarifications be made including who would be 
responsible for making determinations concerning requests for 
confidentiality, confirmation that information will be treated as 
confidential if the requirements in proposed Sec.  190.343(a) are 
followed and that the information would be disclosed only after a 
determination is made in accordance with Sec.  190.343(3)(b). API and 
AOPL also requested that at minimum, operators are granted five 
business days from the date of receipt of a written notice before the 
information is publicly disclosed to object, and requested an 
opportunity for appeal within the agency (e.g., to the Administrator or 
Chief Counsel).
    Energy Transfer Partners commented that some materials required to 
be submitted to PHMSA may contain confidential information regarding 
the operator's markets, plans, anticipated customers, suppliers, 
vendors, contractors, etc. and commented that the proposed language was 
not particularly reassuring that confidentiality would be maintained. 
Energy Transfer Partners also commented that PHMSA should include the 
operator in the decision-making process regarding whether to disclose 
such information.
    Enterprise Products Partners LP commented that industry has long 
relied on FOIA exemptions, established rules for treatment of 
confidential business information and judicially recognized privileges 
and that the rule should clarify that all such protections are 
retained. In addition, Enterprise Products Partners requested that 
PHMSA clarify that it will not post information submitted as 
confidential business information, FOIA exempt or privileged on its 
public Web site without prior notice to the submitter, allow a 
submitter ``at least 5 business days to substantiate a request for 
disclosure of information submitted as CBI, FOIA exempt or privileged, 
and include an expedited appeal process.''
    FlexSteel commented that it strongly objects to the proposal, 
stating that confidential information is information that is intended 
to be private or secret and may be covered by patents or patents 
pending. FlexSteel stated that often the type of supporting 
documentation filed with certain project requests contain patented and 
confidential technological information because it is unique in nature. 
FlexSteel requested that proposed provision Sec.  190.343 be removed.
    Gas Processors Association (GPA) commented that it strongly objects 
to the proposal in Sec.  190.343. GPA stated that pipelines are 
considered critical infrastructure and that virtually every aspect of 
their operations could be deemed sensitive. GPA requested that the 
proposed language in Sec.  190.343 be removed from the final adopted 
rule so that it can be strengthened to provide the greatest amount of 
protections possible for sensitive information.

[[Page 7990]]

    Northeast Gas Association stated that it supports the AGA's 
recommendation that PHMSA provide operators the option of utilizing the 
Protected Critical Infrastructure Information protection protocol under 
the Critical Infrastructure Information Act of 2002 for voluntarily 
submitted sensitive data.
    Texas Pipeline Association (TPA) commented that more robust 
mechanisms for protection from disclosure than what is contained in the 
proposal are needed to protect Sensitive Security Information or 
Protected Critical Infrastructure Information. TPA recommended that the 
proposal in Sec.  190.343 be removed from any final rule adoption and 
that procedures for protection of sensitive and confidential 
information be developed in a separate rulemaking.
3. PHMSA Response
    With this new section, PHMSA is informing submitters of steps to 
follow if they wish to request protection for confidential commercial 
information submitted to PHMSA. This section also includes a provision 
regarding PHMSA's decision. After reviewing the comments received to 
the proposal, PHMSA has made some revisions to the title and regulatory 
text in Sec.  190.343(a) and (b) for clarification.
    In addition to concerns about the protection of confidential 
business information, several commenters raised concerns about 
submitting information that is sensitive for security reasons. PHMSA's 
intent with Sec.  190.343 was to set out the steps for requesting 
protection of confidential commercial information. Therefore, in the 
final rule, PHMSA is revising the title of Sec.  190.343 and regulatory 
text in subparagraph (a) to clarify that this section applies to the 
protection of confidential commercial information.
    PHMSA's review and determinations regarding protection of security 
information involve a different process that is not the subject of this 
rulemaking. Prior to disclosure of information, PHMSA reviews the 
records to determine whether information is protected for security 
reasons and applies all applicable FOIA exemptions and Federal laws. 
The Department of Transportation and Department of Homeland Security 
(DHS) have procedures in place to protect information that is 
determined to be Sensitive Security Information (SSI). PHMSA's Office 
of Pipeline Safety Emergency Support and Security Division consults 
with Departmental and DHS/TSA security offices as necessary.
    The steps set forth in Sec.  190.343(a) serve to notify PHMSA that 
a submitter believes information to be confidential commercial 
information and ensures that PHMSA will protect the information as 
confidential commercial information until it conducts a release 
determination. Generally, such a decision will occur when PHMSA 
receives a FOIA request for the information and completes an analysis 
under FOIA, following the procedures in the Department's FOIA 
regulations in 49 CFR part 7. In an instance where there is not a FOIA 
request, but PHMSA identifies a need to make particular information 
available to the public to support its mission to protect people and 
the environment from the risks of gas, liquefied natural gas, and 
hazardous liquids or carbon dioxide transportation by pipeline, PHMSA 
will use the criteria set out in FOIA to analyze whether the 
information is protected by one or more of the FOIA exemptions.
    Therefore, to address comments, PHMSA revised the regulatory text 
in Sec.  190.343(b) to clarify that PHMSA will use the criteria set 
forth in FOIA if a release determination is necessary. This includes 
complying with the Department's FOIA regulations in 49 CFR 7.29 that 
require consultation with the submitter of information designated as 
confidential commercial information and written notification to the 
submitter of an intended disclosure of the information.
    The procedures in Sec.  190.343 require that at the time of 
submission, the submitter provide PHMSA with an explanation of why the 
information is confidential. Therefore, this section gives submitters 
an opportunity both at the time the information is submitted to PHMSA 
to provide an explanation of why the information is confidential 
commercial information and during the consultation process that PHMSA 
initiates if it has received a FOIA request or determined that there is 
a need to make the information publicly available.
    In response to comments, we are also clarifying in the final rule 
that if after reviewing the submitter's request and explanations 
submitted after the consultation, PHMSA decides to disclose the 
information over the submitter's objections, PHMSA will provide written 
notification to the submitter at least five business days prior to the 
intended disclosure date.
    As PHMSA is following a similar process to that under the 
Departmental FOIA regulations providing for submitter consultation and 
notification, PHMSA is not adding an appeal process for submitters of 
information. If a decision is made that the information is protected as 
confidential commercial information, a FOIA requester who has asked for 
the records has appeal rights under FOIA.
    The Advisory Committees' recommendations also address the public 
comments received by PHMSA.

J. In-Service Welding

1. PHMSA's Proposal
    PHMSA is revising 49 CFR 192.225, 192.227, 195.214, and 195.222 to 
add reference to API 1104, Appendix B.
2. Summary of Public Comment
    The AGA supports PHMSA's proposal to incorporate API 1104 Appendix 
B as an acceptable section for the development of welding procedures 
and welder qualification. It does not believe that this change creates 
a new requirement to only use API 1104 Appendix B to qualify in service 
welding procedures or in service welders and, therefore, requests that 
PHMSA should provide clarification in the preamble language of the 
final rule by stating this incorporation does not create a new 
requirement.
    Northeast Gas Association commented that it supports PHMSA's 
proposal to incorporate API 11 04 Appendix B as an acceptable section 
for the development of welding procedures and welder qualification, as 
long as this change provides another option along with the existing 
options in the regulations.
3. PHMSA Response
    In the past, PHMSA has encouraged pipeline operators to develop and 
use welding procedures that address improvements in pipeline safety and 
many operators have developed in service welding procedures. Welding 
procedures developed to API 1104 Appendix B consider the risks 
associated with hydrogen in the weld metal, type of welding electrode, 
sleeve/fitting and carrier pipe materials, accelerated cooling, and 
stresses across the fillet welds. Parts 192 and 195 do not include the 
addition of API 1104 Appendix B as an acceptable section for the 
development of welding procedures and welder qualification. To allow 
in-service welding, PHMSA is adopting Appendix B of API 1104 into parts 
192 and 195. Therefore, PHMSA is not creating new requirement but only 
including Appendix B into already adopted API 1104 to qualify in 
service welding procedures or in service welders to perform in-service 
welding operators must follow Appendix B of API 1104. In addition, 
currently,

[[Page 7991]]

PHMSA does not allow in service welding and, therefore, there are no 
existing options in the regulations for in service welding.
    The Advisory Committees agreed with PHMSA's responses to the public 
comments.

K. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192, 
193, and 195 all or parts of more than 60 standards and specifications 
developed and published by standard developing organizations (SDOs). In 
general, SDOs update and revise their published standards every 3 to 5 
years to reflect modern technology and best technical practices.
    The National Technology Transfer and Advancement Act of 1995, 
Public Law 104-113, directs Federal agencies to use voluntary consensus 
standards in lieu of government-written standards whenever possible. 
Voluntary consensus standards are standards developed or adopted by 
voluntary bodies that develop, establish, or coordinate technical 
standards using agreed-upon procedures. In addition, Office of 
Management and Budget (OMB) issued OMB Circular A-119 to implement 
section 12(d) of Public Law 104-113 relative to the utilization of 
consensus technical standards by Federal agencies. This circular 
provides guidance for agencies participating in voluntary consensus 
standards bodies and describes procedures for satisfying the reporting 
requirements in Public Law 104-113.
    In accordance with the preceding provisions, PHMSA has the 
responsibility for determining, via petitions or otherwise, which 
currently referenced standards should be updated, revised, or removed, 
and which standards should be added to 49 CFR parts 192, 193, and 195. 
Revisions to incorporate by reference materials in 49 CFR parts 192, 
193, and 195 are handled via the rulemaking process, which allows for 
the public and regulated entities to provide input. During the 
rulemaking process, PHMSA must also obtain approval from the Office of 
the Federal Register to incorporate by reference any new materials.
    On January 3, 2012, President Obama signed the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90. 
Section 24 states, ``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.'' 49 
U.S.C. 60102(p). On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 
60102(p) to replace ``1 year'' with ``3 years'' and remove the phrases 
``guidance or'' and, ``on an Internet Web site.'' This resulted in the 
current language in 49 U.S.C. 60102(p), which now reads as follows, 
``Beginning 3 years after the date of enactment of this subsection, the 
Secretary may not issue 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.''
    Further, the Office of the Federal Register issued a November 7, 
2014, rulemaking that revised 1 CFR 51.5 to require that agencies 
detail in the preamble of a rulemaking the ways the materials it 
incorporates by reference are reasonably available to interested 
parties, or how the agency worked to make those materials reasonably 
available to interested parties. 79 FR 66278. In relation to this 
rulemaking, PHMSA has contacted each SDO and has requested free public 
access of each standard that has been incorporation by reference. The 
SDOs agreed to make viewable copies of the incorporated standards 
available to the public at no cost. Pipeline operators interested in 
purchasing these standards can contact the standards organization. The 
contact information is provided in this rulemaking action, see Sec.  
195.3.

V. Regulatory Analyses and Notices

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

    This rule is a non-significant regulatory action under Section 3(f) 
of Executive Order 12866, 58 FR 51735, and; therefore, it was not 
reviewed by the Office of Management and Budget. This rule is non-
significant under the Regulatory Policies and Procedures of the 
Department of Transportation. 44 FR 11034.
    Executive Order 12866, as supplemented by Executive Order 13563, 76 
FR 3821, requires agencies regulate in the most cost-effective manner, 
make a reasoned determination that the benefits of the intended 
regulation justify its costs, and develop regulations that impose the 
least burden on society. In this rule, PHMSA is amending the pipeline 
safety regulations to:
     Add a specific time frame for telephonic or electronic 
notifications of accidents and incidents;
     Establish PHMSA's cost recovery procedures for new 
projects that cost over $2,500,000,000 or use new and novel 
technologies;
     Address the NTSB's recommendations to clarify training 
requirements for control room team members;
     Add provisions for the renewal of expiring special 
permits;
     Exclude farm taps from the requirements of the DIMP 
requirements while adding safety requirements for the farm taps;
     Require pipeline operators to report to PHMSA for 
permanent reversal of flow that lasts more than 30 days or to a change 
in product;
     Provide methods for assessment tools by incorporating 
consensus standards by reference in part 195 for ILI and SCCDA (also 
addresses part of NTSB recommendation);
     Require electronic reporting of drug and alcohol testing 
results in part 199;
     Modify the criteria used to make decisions about 
conducting post-accident drug and alcohol tests and require operators 
to keep for at least three years a record of the reason why post-
accident drug and alcohol test was not conducted (also addresses NTSB 
recommendation);
     Include the procedure for requesting protection of 
confidential commercial information submitted to PHMSA.
     Add reference to Appendix B of API 1104 related to in-
service welding in Parts 192 and 195; and
     Make minor editorial corrections.
    The regulatory impact analysis found, in summary, that annual 
compliance costs would be approximately $0.6 million, less savings to 
be realized from the removal of farm taps from the Distribution 
Integrity Management Program (DIMP) requirements.
    Annual benefits could not be quantified as readily due to data 
limitations and the very minor nature of many of the changes. PHMSA 
expects that the improvements and clarifications made to the 
regulations, including those for post-incident investigations along 
with other provisions, will reduce pipeline incidents and the 
associated consequences, including the potential to prevent a future 
high-consequence event, such as those that have occurred on gas 
transmission and hazardous liquid pipelines in the past.

Regulatory Flexibility Act

    The Regulatory Flexibility Act requires an agency to review 
regulations

[[Page 7992]]

to assess their impact on small entities, unless the agency determines 
that a rule is not expected to have a significant impact on a 
substantial number of small entities. 5 U.S.C. 601 et seq. This final 
rule has been developed in accordance with Executive Order 13272, 
``Proper Consideration of Small Entities in Agency Rulemaking,'' 67 FR 
53461, and DOT's procedures and policies to promote compliance with the 
Regulatory Flexibility Act to ensure that potential impacts of rules on 
small entities are properly considered.
    The Initial Regulatory Flexibility Analysis found that the rule 
could affect a substantial number of small entities because of the 
market structure of the gas and hazardous liquids pipeline industry, 
which includes many small entities. However, these impacts would not be 
significant. The post-accident drug testing provision would add $74 in 
documentation costs per reportable incident. The other provisions would 
not add appreciable costs, and at least one provision (farm taps) would 
yield compliance cost savings.
Description of the Reasons Why Action by PHMSA Is Being Considered
    PHMSA is amending the regulations to address the 2011 Act's section 
9 (accident and incident reporting requirements) to within one hour so 
that timely actions can be taken to pipeline accidents and incidents, 
and section 13 (cost recovery) so that PHMSA's limited resources for 
enforcement and other safety activities are not used for operators 
design reviews. NTSB recommendations for control room training and drug 
and alcohol reporting requirements are addressed under this rule. A 
special permit renewal procedure is added so that pipeline operators 
have a renewal procedure to follow to renew their expiring special 
permits. In addition, other non-substantive changes are amended to 
correct language and provide methods for assessment tools as 
recommended by incorporating consensus standards (this addresses parts 
of NTSB recommendations P-12-3 and the NACE recommendations). 
Specifically, these amendments address: Farm tap requirements to 
address the NAPSR and INGAA concerns in including farm taps under the 
DIMP requirements; notification for reversal of flow or change in 
product for more than 60 days so that PHMSA is aware of the transported 
product; incorporation by reference of standards to address ILI and 
SCCDA; and additional testing of drug and alcohol tests, electronic 
reporting of drug and alcohol testing results, modifying the criteria 
used to make decisions about conducting post-accident drug and alcohol 
tests and post-accident drug and alcohol testing recordkeeping to 
address a NTSB recommendation; the process to request confidential 
treatment of submitted information similar to the process currently set 
out in 49 CFR 105.30 of the Hazardous Materials Regulations; and, 
editorial amendments to correct some errors or outdated deadlines.
Succinct Statement of the Objectives of, and Legal Basis for, This Rule
    Under the Federal 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 this authority to the PHMSA Administrator. 49 CFR 
1.97(a). This rulemaking action will create changes in the regulations 
consistent with the protection of persons and property while changing 
unduly burdensome or nonsensical requirements.
Description of Small Entities to Which This Rulemaking Action Will 
Apply
    The initial Regulatory Flexibility Analysis found that the rule 
could affect a substantial number of small entities because of the 
market structure of the gas and hazardous liquids pipeline industry, 
which includes many small entities. However, these impacts would not be 
significant. The provision to document the reason for not drug testing 
post-accident adds $74 in documentation costs per reportable incident. 
The other provisions would not add appreciable costs, and at least one 
provision (Farm Taps) would yield compliance cost savings, though those 
savings are minimal.
Description of Any Significant Alternatives to This Rule That 
Accomplish the Stated Objectives of Applicable Statutes and That 
Minimize Any Significant Economic Impact of the 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.

Executive Order 13175

    PHMSA has analyzed this rule according to the principles and 
criteria in Executive Order 13175, ``Consultation and Coordination with 
Indian Tribal Governments,'' 65 FR 67249. The funding and consultation 
requirements of Executive Order 13175 do not apply because this rule 
does not significantly or uniquely affect the communities of Indian 
tribal governments or impose substantial direct compliance costs.

Paperwork Reduction Act

    PHMSA has analyzed this final rule in accordance with the Paperwork 
Reduction Act of 1995 (PRA). Public Law 96-511. The PRA requires 
federal agencies to minimize paperwork burden imposed on the American 
public by ensuring maximum utility and quality of federal information, 
ensuring the use of information technology to improve government 
performance, and improving the federal government's accountability for 
managing information collection activities. Pursuant to 5 CFR 
1320.8(d), PHMSA is required to provide interested members of the 
public and affected agencies with an opportunity to comment on 
information collection and recordkeeping requests. PHMSA estimates that 
this rulemaking action will impact the following information 
collections:
    ``Transportation of Hazardous Liquids by Pipeline: Record keeping 
and Accident Reporting'' identified under Office of Management and 
Budget (OMB) Control Number 2137-0047; ``Incident and Annual Reports 
for Gas Pipeline Operators'' identified under Office of Management and 
Budget (OMB) Control Number 2137-0522; ``Qualification of Pipeline 
Safety Training'' identified under Office of Management and Budget 
(OMB) Control Number 2137-0600; and ``National Registry of Pipeline and 
LNG Operators'' identified under Office of Management and Budget (OMB) 
Control Number 2137-0627.
    PHMSA is also creating a new information collection to cover the 
recordkeeping requirement for post-accident drug testing: ``Post-
Accident Drug Testing for Pipeline Operators.'' PHMSA will request a 
new Control Number from the Office of Management and Budget (OMB) for 
this information collection.
    PHMSA will submit an information collection revision request to OMB 
for approval based on the requirements that need information collection 
in this proposed rule. The information collection is contained in the 
pipeline safety regulations, 49 CFR parts 190 through 199. The 
following information is provided for each information collection: (1) 
Title of the information collection; (2) OMB control number; (3) 
Current expiration date; (4) Type of request; (5) Abstract of the 
information collection activity; (6) Description of affected public; 
(7) Estimate of total annual reporting and recordkeeping

[[Page 7993]]

burden; and (8) Frequency of collection. The information collection 
burdens are estimated to be revised as follows:

    1. Title: Transportation of Hazardous Liquids by Pipeline: 
Recordkeeping and Accident Reporting.
    OMB Control Number: 2137-0047.
    Current Expiration Date: December 31, 2016.
    Abstract: This information collection covers recordkeeping and 
accident reporting by hazardous liquid pipeline operators who are 
subject to 49 CFR part 195. Section 195.50 specifies the definition of 
an ``accident'' and the reporting criteria for submitting a Hazardous 
Liquid Accident Report (form PHMSA F7000-1) is detailed in Sec.  
195.54. PHMSA is revising the form PHMSA F7000-1 and its instructions 
to include the concept of ``confirmed discovery'' as amended in this 
rule. Operators will be required to include the date and time of the 
confirmed discovery of a hazardous liquid pipeline accident. PHMSA does 
not expect this revision to increase the burden of reporting.
    Affected Public: Hazardous liquid pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 847.
    Total Annual Burden Hours: 52,429.
    Frequency of collection: On Occasion.

    2. Title: Incident and Annual Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: October 31, 2017.
    Abstract: This rulemaking action will result in a modification to 
three gas incident forms to include the concept of ``confirmed 
discovery'' as amended in this rule. Operators will be required to 
include the date and time of the confirmed discovery of a natural gas 
pipeline incident. PHMSA does not expect this revision to increase the 
burden of reporting.
    Affected Public: Gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 12,164.
    Total Annual Burden Hours: 92,321.
    Frequency of Collection: On occasion.

    3. Title: ``National Registry of Pipeline and LNG Operators''
    OMB Control Number: 2137-0627.
    Current Expiration Date: May 31, 2018.
    Abstract: The National Registry of Pipeline and LNG Operators 
serves as the storehouse of data on regulated operators or those 
subject to reporting requirements under 49 CFR parts 192, 193, or 195. 
This registry incorporates the use of two forms: (1) The Operator 
Assignment Request Form (PHMSA F 1000.1) and, (2) the Operator Registry 
Notification Form (PHMSA F 1000.2). This rule amends Sec.  191.22 to 
require operators to notify PHMSA upon the occurrence of the following: 
Construction of 10 or more miles of a new or replacement pipeline; 
construction of a new LNG plant or LNG facility; reversal of product 
flow direction when the reversal is expected to last more than 30 days; 
if a pipeline is converted for service under Sec.  192.14, or has a 
change in commodity as reported on the annual report as required by 
Sec.  191.17.
    These notifications are estimated to be rare but would fall under 
the scope of Operator Notifications required by PHMSA as a result of 
this rule. PHMSA estimates that this new reporting requirement will add 
10 new responses and 10 annual burden hours to the currently approved 
information collection.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 640.
    Total Annual Burden Hours: 640.
    Frequency of Collection: On occasion.

    4. Title: ``Post-Accident Drug Testing for Pipeline Operators''
    OMB Control Number: Will request one from OMB.
    Current Expiration Date: New Collection--To be determined.
    Abstract: This rule amends 49 CFR 199.227 to require operators to 
retain records for three years if they decide not to administer post-
accident/incident drug testing on affected employees). As a result, 
operators who choose not to perform post-accident drug and alcohol 
tests on affected employees are required to keep records explaining 
their decision not to do so. PHMSA estimates this recordkeeping 
requirement will result in 609 responses and 1,218 burden hours for 
recordkeeping. PHMSA does not currently have an information collection 
which covers this requirement and will request the approval of this new 
collection, along with a new OMB Control Number, from the Office of 
Management and Budget.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 609.
    Total Annual Burden Hours: 1,218.
    Frequency of Collection: On occasion.
    Requests for copies of these information collections should be 
directed to Angela Dow, Office of Pipeline Safety (PHP-30), Pipeline 
and Hazardous Materials Safety Administration, 2nd Floor, 1200 New 
Jersey Avenue SE., Washington, DC 20590-0001. Telephone: 202-366-1246.

Unfunded Mandates Reform Act of 1995

    This final rule does not impose unfunded mandates under the 
Unfunded Mandates Reform Act of 1995. Public Law 104-4. PHMSA has 
determined that the rule does not impose annual expenditures on State, 
local, or tribal governments of the private sector in excess of $155 
million, and thus, does not require an Unfunded Mandates Act 
analysis.\7\
---------------------------------------------------------------------------

    \7\ The Unfunded Mandates Act threshold was $100 million in 
1995. Using the non-seasonally adjusted CPI-U (Index series 
CUUR000SA0), that number is $155 million in 2014 dollars.
---------------------------------------------------------------------------

National Environmental Policy Act

    The National Environmental Policy Act, 42 U.S.C. 4321 through 4375, 
requires that Federal agencies analyze rulemaking actions to determine 
whether those actions will have a significant impact on the human 
environment. The Council on Environmental Quality regulations, 40 CFR 
parts 1500-1508, require Federal agencies to conduct an environmental 
review considering: (1) The need for the regulatory action, (2) 
alternatives to the regulatory action, (3) probable environmental 
impacts of the regulatory action and alternatives, and (4) the agencies 
and persons consulted during the rulemaking development 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 action is to enhance pipeline integrity and safety to lessen 
the frequency and consequences of pipeline incidents that cause 
environmental degradation, personal injury, and loss of life.
    The need for this action stems from the statutory mandates in 
sections 9 and 13 of the 2011 Act, NTSB recommendations, and the need 
to add new reference material and make non substantive edits. Section 9 
of the 2011 Act directs PHMSA to require a specific time limit for 
telephonic or electronic reporting of pipeline accidents and incidents, 
and section 13 of the 2011 Act allows PHMSA to recover costs associated 
with pipeline design reviews. NTSB has made recommendations regarding 
the clarification of OQ requirements in control rooms, and to eliminate 
operator discretion with regard to post-accident drug and alcohol

[[Page 7994]]

testing of covered employees. In addition, PHMSA's safety regulations 
require periodic updates and clarifications to enhance compliance and 
overall safety.
2. Alternatives
    In developing this rulemaking action, PHMSA considered two 
alternatives:
    (1) No action, or
    (2) Amend revisions to the pipeline safety regulations to 
incorporate the amendments as described in this document.
    Alternative 1: PHMSA has an obligation to ensure the safe and 
effective transportation of hazardous liquids and gases by pipeline. 
The changes in this rulemaking action serve that purpose by clarifying 
the pipeline safety regulations and addressing Congressional mandates 
and NTSB safety recommendations. A failure to undertake these actions 
would be non-responsive to the Congressional mandates and the NTSB 
recommendations. Accordingly, PHMSA rejected the ``no action'' 
alternative.
    Alternative 2: PHMSA is making certain amendments and non-
substantive changes to the pipeline safety regulations to add a 
specific time frame for telephonic or electronic notifications of 
accidents and incidents and add provisions for cost recovery for design 
reviews of certain new projects, for the renewal of expiring special 
permits, and to request PHMSA keep submitted information confidential. 
PHMSA is also making changes to the drug and alcohol testing 
requirements, control room team training requirements, and is providing 
methods for assessment tools by incorporating consensus standards by 
reference for ILI and SCCDA.
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 2.6 million miles of pipelines 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 environments potentially affected by this rule 
includes the 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 habitats, forests, grasslands, offshore marine ecosystems), and 
special ecological resources (e.g., threatened and endangered plant and 
animal species and their habitats, 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 this rule contain hazardous 
materials, resources within the physically affected environments, as 
well as public health and safety, may be affected by 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 
impacts could vary from property damage and environmental damage to 
injuries or, on rare occasions, fatalities.
    The amendments are improvements to the existing pipeline safety 
requirements and would have little or no impact on the human 
environment. On a national scale, the cumulative environmental damage 
from pipelines would most likely be reduced slightly.
    For these reasons, PHMSA has concluded that neither of the 
alternatives discussed above would result in any significant impacts on 
the environment.
    Preparers: This Environmental Assessment was prepared by DOT staff 
from PHMSA and Volpe National Transportation Systems Center (Office of 
the Secretary for Research and Technology (OST-R)).
4. Finding of No Significant Impact
    PHMSA has determined that the selected alternative would have a 
positive, non-significant, impact on the human environment.

Executive Order 13132

    PHMSA has analyzed this rule according to Executive Order 13132, 
``Federalism,'' 64 FR 43255. The 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 rule does 
not impose substantial direct compliance costs on State and local 
governments. This 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 rule is not a ``significant energy action'' under Executive 
Order 13211, ``Actions Concerning Regulations That Significantly Affect 
Energy Supply, Distribution, or Use,'' 66 FR 28355. It is not likely to 
have a significant adverse effect on supply, distribution, or energy 
use. Further, the Office of Information and Regulatory Affairs has not 
designated this rule as a significant energy action.
Regulation Identifier Number
    A regulation identifier number (RIN) is assigned to each regulatory 
action listed in the Unified Agenda of Federal Regulations. The 
Regulatory Information Service Center publishes the Unified Agenda in 
spring and fall of each year. The RIN contained in the heading of this 
document can be used to cross-reference this action with the United 
Agenda.

List of Subjects

49 CFR Part 190

    Administrative practice and procedure, Penalties, Cost recovery, 
Special permits.

49 CFR Part 191

    Incident, Pipeline safety, Reporting and recordkeeping 
requirements, Reversal of flow.

49 CFR Part 192

    Control room, Distribution integrity management program, Gathering 
lines, Incorporation by reference, Operator qualification, Pipeline 
safety, Safety devices, Security measures.

49 CFR Part 195

    Ammonia, Carbon dioxide, Control room, Corrosion control, Direct 
and indirect costs, Gathering lines, Incident, Incorporation by 
reference, Operator qualification, Petroleum, Pipeline safety, 
Reporting and recordkeeping requirements, Reversal of flow, and Safety 
devices.

49 CFR Part 199

    Alcohol testing, Drug testing, Pipeline safety, Reporting and 
recordkeeping requirements, Safety, and Transportation.

    In consideration of the foregoing, PHMSA is amending 49 CFR parts 
190, 191, 192, 195, and 199 as follows:

[[Page 7995]]

PART 190--PIPELINE SAFETY ENFORCEMENT AND REGULATORY PROCEDURES

0
1. The authority citation for part 190 continues to read as follows:

    Authority: 33 U.S.C. 1321(b); 49 U.S.C. 60101 et seq.; 49 CFR 
1.97.


0
2. In Sec.  190.3, add the definition ``New and novel technologies'' in 
alphabetical order to read as follows:


Sec.  190.3  Definitions.

* * * * *
    New and novel technologies means any products, designs, materials, 
testing, construction, inspection, or operational procedures that are 
not addressed in 49 CFR parts 192, 193, or 195, due to technology or 
design advances and innovation for new construction. Technologies that 
are addressed in consensus standards that are incorporated by reference 
into parts 192, 193, and 195 are not ``new or novel technologies.''
* * * * *

0
3. Amend Sec.  190.341 by:
0
a. Revising paragraph (c)(8) and removing paragraph (c)(9) and revising 
paragraph (d);
0
b. Re-designating paragraphs (e) through (j) as paragraphs (g) through 
(l) and adding new paragraphs (e) and (f).
    The additions and revisions read as follows:


Sec.  190.341  Special permits.

* * * * *
    (c) * * *
    (8) Any other information PHMSA may need to process the application 
including environmental analysis where necessary.
    (d) How does PHMSA handle special permit applications?--(1) Public 
notice. Upon receipt of an application or renewal of a special permit, 
PHMSA will provide notice to the public of its intent to consider the 
application and invite comment. In addition, PHMSA may consult with 
other Federal agencies before granting or denying an application or 
renewal on matters that PHMSA believes may have significance for 
proceedings under their areas of responsibility.
    (2) Grants, renewals, and denials. If the Associate Administrator 
determines that the application complies with the requirements of this 
section and that the waiver of the relevant regulation or standard is 
not inconsistent with pipeline safety, the Associate Administrator may 
grant the application, in whole or in part, for a period of time from 
the date granted. Conditions may be imposed on the grant if the 
Associate Administrator concludes they are necessary to assure safety, 
environmental protection, or are otherwise in the public interest. If 
the Associate Administrator determines that the application does not 
comply with the requirements of this section or that a waiver is not 
justified, the application will be denied. Whenever the Associate 
Administrator grants or denies an application, notice of the decision 
will be provided to the applicant. PHMSA will post all special permits 
on its Web site at http://www.phmsa.dot.gov/.
    (e) How does PHMSA handle special permit renewals? (1) The grantee 
of the special permit must apply for a renewal of the permit 180 days 
prior to the permit expiration.
    (2) If, at least 180 days before an existing special permit expires 
the holder files an application for renewal that is complete and 
conforms to the requirements of this section, the special permit will 
not expire until final administrative action on the application for 
renewal has been taken:
    (i) Direct fax to PHMSA at: 202-366-4566; or
    (ii) Express mail, or overnight courier to the Associate 
Administrator for Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 
20590.
    (f) What information must be included in the renewal application? 
(1) The renewal application must include a copy of the original special 
permit, the docket number on the special permit, and the following 
information as applicable:
    (i) A summary report in accordance with the requirements of the 
original special permit including verification that the grantee's 
operations and maintenance plan (O&M Plan) is consistent with the 
conditions of the special permit;
    (ii) Name, mailing address and telephone number of the special 
permit grantee;
    (iii) Location of special permit--areas on the pipeline where the 
special permit is applicable including: Diameter, mile posts, county, 
and state;
    (iv) Applicable usage of the special permit--original and future; 
and
    (v) Data for the special permit segment and area identified in the 
special permit as needing additional inspections to include, as 
applicable:
    (A) Pipe attributes: Pipe diameter, wall thickness, grade, seam 
type; and pipe coating including girth weld coating;
    (B) Operating Pressure: Maximum allowable operating pressure 
(MAOP); class location (including boundaries on aerial photography);
    (C) High Consequence Areas (HCAs): HCA boundaries on aerial 
photography;
    (D) Material Properties: Pipeline material documentation for all 
pipe, fittings, flanges, and any other facilities included in the 
special permit. Material documentation must include: Yield strength, 
tensile strength, chemical composition, wall thickness, and seam type;
    (E) Test Pressure: Hydrostatic test pressure and date including 
pressure and temperature charts and logs and any known test failures or 
leaks;
    (F) In-line inspection (ILI): Summary of ILI survey results from 
all ILI tools used on the special permit segments during the previous 
five years or latest ILI survey result;
    (G) Integrity Data and Integration: The following information, as 
applicable, for the past five (5) years: Hydrostatic test pressure 
including any known test failures or leaks; casings(any shorts); any 
in-service ruptures or leaks; close interval survey (CIS) surveys; 
depth of cover surveys; rectifier readings; test point survey readings; 
alternating current/direct current (AC/DC) interference surveys; pipe 
coating surveys; pipe coating and anomaly evaluations from pipe 
excavations; stress corrosion cracking (SCC), selective seam weld 
corrosion (SSWC) and hard spot excavations and findings; and pipe 
exposures from encroachments;
    (H) In-service: Any in-service ruptures or leaks including repair 
type and failure investigation findings; and
    (I) Aerial Photography: Special permit segment and special permit 
inspection area, if applicable.
    (2) PHMSA may request additional operational, integrity or 
environmental assessment information prior to granting any request for 
special permit renewal.
    (3) The existing special permit will remain in effect until PHMSA 
acts on the application for renewal by granting or denying the request.
* * * * *

0
4. Section 190.343 is added to subpart D read as follows:


Sec.  190.343  Information made available to the public and request for 
protection of confidential commercial information.

    When you submit information to PHMSA during a rulemaking 
proceeding, as part of your application for special permit or renewal, 
or for any other reason, we may make that information publicly 
available unless you ask that we keep the information confidential.

[[Page 7996]]

    (a) Asking for protection of confidential commercial information. 
You may ask us to give confidential treatment to information you give 
to the agency by taking the following steps:
    (1) Mark ``confidential'' on each page of the original document you 
would like to keep confidential.
    (2) Send us, along with the original document, a second copy of the 
original document with the confidential commercial information deleted.
    (3) Explain why the information you are submitting is confidential 
commercial information.
    (b) PHMSA decision. PHMSA will treat as confidential the 
information that you submitted in accordance with this section, unless 
we notify you otherwise. If PHMSA decides to disclose the information, 
PHMSA will review your request to protect confidential commercial 
information under the criteria set forth in the Freedom of Information 
Act (FOIA), 5 U.S.C. 552, including following the consultation 
procedures set out in the Departmental FOIA regulations, 49 CFR 7.29. 
If PHMSA decides to disclose the information over your objections, we 
will notify you in writing at least five business days before the 
intended disclosure date.

0
5. In part 190, subpart E is added to read as follows:

Subpart E--Cost Recovery for Design Reviews

Sec.
190.401 Scope.
190.403 Applicability.
190.405 Notification.
190.407 Master Agreement.
190.409 Fee structure.
190.411 Procedures for billing and payment of fee.


Sec.  190.401  Scope.

    If PHMSA conducts a facility design and/or construction safety 
review or inspection in connection with a proposal to construct, 
expand, or operate a gas, hazardous liquid or carbon dioxide pipeline 
facility, or a liquefied natural gas facility that meets the 
applicability requirements in Sec.  190.403, PHMSA may require the 
applicant proposing the project to pay the costs incurred by PHMSA 
relating to such review, including the cost of design and construction 
safety reviews or inspections.


Sec.  190.403  Applicability.

    The following paragraph specifies which projects will be subject to 
the cost recovery requirements of this section.
    (a) This section applies to any project that--
    (1) Has design and construction costs totaling at least 
$2,500,000,000, as periodically adjusted by PHMSA, to take into account 
increases in the Consumer Price Index for all urban consumers published 
by the Department of Labor, based on--
    (i) The cost estimate provided to the Federal Energy Regulatory 
Commission in an application for a certificate of public convenience 
and necessity for a gas pipeline facility or an application for 
authorization for a liquefied natural gas pipeline facility; or
    (ii) A good faith estimate developed by the applicant proposing a 
hazardous liquid or carbon dioxide pipeline facility and submitted to 
the Associate Administrator. The good faith estimate for design and 
construction costs must include all of the applicable cost items 
contained in the Federal Energy Regulatory Commission application 
referenced in Sec.  190.403(a)(1)(i) for a gas or LNG facility. In 
addition, an applicant must take into account all survey, design, 
material, permitting, right-of way acquisition, construction, testing, 
commissioning, start-up, construction financing, environmental 
protection, inspection, material transportation, sales tax, project 
contingency, and all other applicable costs, including all segments, 
facilities, and multi-year phases of the project;
    (2) Uses new or novel technologies or design, as defined in Sec.  
190.3.
    (b) The Associate Administrator may not collect design safety 
review fees under this section and 49 U.S.C. 60301 for the same design 
safety review.
    (c) The Associate Administrator, after receipt of the design 
specifications, construction plans and procedures, and related 
materials, determines if cost recovery is necessary. The Associate 
Administrator's determination is based on the amount of PHMSA resources 
needed to ensure safety and environmental protection.


Sec.  190.405  Notification.

    For any new pipeline facility construction project in which PHMSA 
will conduct a design review, the applicant proposing the project must 
notify PHMSA and provide the design specifications, construction plans 
and procedures, project schedule and related materials at least 120 
days prior to the commencement of any of the following activities: 
Route surveys for construction, material manufacturing, offsite 
facility fabrications, construction equipment move-in activities, 
onsite or offsite fabrications, personnel support facility 
construction, and any offsite or onsite facility construction. To the 
maximum extent practicable, but not later than 90 days after receiving 
such design specifications, construction plans and procedures, and 
related materials, PHMSA will provide written comments, feedback, and 
guidance on the project.


Sec.  190.407  Master Agreement.

    PHMSA and the applicant will enter into an agreement within 60 days 
after PHMSA received notification from the applicant provided in Sec.  
190.405, outlining PHMSA's recovery of the costs associated with the 
facility design safety review.
    (a) A Master Agreement, at a minimum, includes:
    (1) Itemized list of direct costs to be recovered by PHMSA;
    (2) Scope of work for conducting the facility design safety review 
and an estimated total cost;
    (3) Description of the method of periodic billing, payment, and 
auditing of cost recovery fees;
    (4) Minimum account balance which the applicant must maintain with 
PHMSA at all times;
    (5) Provisions for reconciling differences between total amount 
billed and the final cost of the design review, including provisions 
for returning any excess payments to the applicant at the conclusion of 
the project;
    (6) A principal point of contact for both PHMSA and the applicant; 
and
    (7) Provisions for terminating the agreement.
    (8) A project reimbursement cost schedule based upon the project 
timing and scope.
    (b) [Reserved]


Sec.  190.409  Fee structure.

    The fee charged is based on the direct costs that PHMSA incurs in 
conducting the facility design safety review (including construction 
review and inspections), and will be based only on costs necessary for 
conducting the facility design safety review. ``Necessary for'' means 
that but for the facility design safety review, the costs would not 
have been incurred and that the costs cover only those activities and 
items without which the facility design safety review cannot be 
completed.
    (a) Costs qualifying for cost recovery include, but are not limited 
to--
    (1) Personnel costs based upon total cost to PHMSA;
    (2) Travel, lodging and subsistence;
    (3) Vehicle mileage;
    (4) Other direct services, materials and supplies;
    (5) Other direct costs as may be specified in the Master Agreement.
    (b) [Reserved]

[[Page 7997]]

Sec.  190.411  Procedures for billing and payment of fee.

    All PHMSA cost calculations for billing purposes are determined 
from the best available PHMSA records.
    (a) PHMSA bills an applicant for cost recovery fees as specified in 
the Master Agreement, but the applicant will not be billed more 
frequently than quarterly.
    (1) PHMSA will itemize cost recovery bills in sufficient detail to 
allow independent verification of calculations.
    (2) [Reserved]
    (b) PHMSA will monitor the applicant's account balance. Should the 
account balance fall below the required minimum balance specified in 
the Master Agreement, PHMSA may request at any time the applicant 
submit payment within 30 days to maintain the minimum balance.
    (c) PHMSA will provide an updated estimate of costs to the 
applicant on or near October 1st of each calendar year.
    (d) Payment of cost recovery fees is due within 30 days of issuance 
of a bill for the fees. If payment is not made within 30 days, PHMSA 
may charge an annual rate of interest (as set by the Department of 
Treasury's Statutory Debt Collection Authorities) on any outstanding 
debt, as specified in the Master Agreement.
    (e) Payment of the cost recovery fee by the applicant does not 
obligate or prevent PHMSA from taking any particular action during 
safety inspections on the project.

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; 
ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION 
REPORTS

0
6. 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 60141; and 49 CFR 1.97.


0
7. In Sec.  191.3, add the definition ``Confirmed Discovery'' in 
alphabetical order to read as follows:


Sec.  191.3  Definitions.

* * * * *
    Confirmed Discovery means when it can be reasonably determined, 
based on information available to the operator at the time a reportable 
event has occurred, even if only based on a preliminary evaluation.
* * * * *

0
8. In Sec.  191.5, paragraph (a) is revised and paragraph (c) is added 
to read as follows:


Sec.  191.5  Immediate notice of certain incidents.

    (a) At the earliest practicable moment following discovery, but no 
later than one hour after confirmed discovery, each operator must give 
notice in accordance with paragraph (b) of this section of each 
incident as defined in Sec.  191.3.
* * * * *
    (c) Within 48 hours after the confirmed discovery of an incident, 
to the extent practicable, an operator must revise or confirm its 
initial telephonic notice required in paragraph (b) of this section 
with an estimate of the amount of product released, an estimate of the 
number of fatalities and injuries, and all other significant facts that 
are known by the operator that are relevant to the cause of the 
incident or extent of the damages. If there are no changes or revisions 
to the initial report, the operator must confirm the estimates in its 
initial report.

0
9. In Sec.  191.22, paragraph (c)(1)(ii) is revised and paragraphs 
(c)(1)(v) and (c)(1)(vi) are added to read as follows:


Sec.  191.22  National Registry of Pipeline and LNG operators

* * * * *
    (c) * * *
    (1) * * *
    (ii) Construction of 10 or more miles of a new or replacement 
pipeline;
* * * * *
    (v) Reversal of product flow direction when the reversal is 
expected to last more than 30 days. This notification is not required 
for pipeline systems already designed for bi-directional flow; or
    (vi) A pipeline converted for service under Sec.  192.14 of this 
chapter, or a change in commodity as reported on the annual report as 
required by Sec.  191.17.
* * * * *

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

0
10. 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, 60118, 60137, 60141; and 49 CFR 1.97.


0
11. In Sec.  192.14, paragraph (c) is added to read as follows


Sec.  192.14  Conversion to service subject to this part.

* * * * *
    (c) An operator converting a pipeline from service not previously 
covered by this part must notify PHMSA 60 days before the conversion 
occurs as required by Sec.  191.22 of this chapter.

0
12. In Section 192.175, paragraph (b) is revised to read as follows:


Sec.  192.175  Pipe-type and bottle-type holders.

* * * * *
    (b) Each pipe-type or bottle-type holder must have minimum 
clearance from other holders in accordance with the following formula:

C = (3D*P*F)/1000) in inches; (C = (3D*P*F*)/6,895) in millimeters


in which:

C = Minimum clearance between pipe containers or bottles in inches 
(millimeters).
D = Outside diameter of pipe containers or bottles in inches 
(millimeters).
P = Maximum allowable operating pressure, psi (kPa) gauge.
F = Design factor as set forth in Sec.  192.111 of this part.


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, Appendix A or Appendix B of API Std 1104 (incorporated 
by reference, see Sec.  192.7), or section IX of the ASME Boiler and 
Pressure Vessel Code (ASME BPVC) (incorporated by reference, see Sec.  
192.7) to produce welds meeting 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 applicable 
welding standard(s).
* * * * *

0
14. In Sec.  192.227, paragraph (a) is revised to read as follows:


Sec.  192.227  Qualification of welders.

    (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, Appendix A or Appendix B of API Std 1104 (incorporated 
by reference, see Sec.  192.7), or section IX of the ASME Boiler and 
Pressure Vessel Code (ASME BPVC) (incorporated by reference, see Sec.  
192.7). However, a welder or welding operator qualified under an 
earlier edition than the listed in Sec.  192.7 of this part may weld 
but may not requalify under that earlier edition.
* * * * *

0
15. In Sec.  192.631, paragraphs (b)(3) and (4) are revised, paragraph 
(b)(5) is added, paragraphs (h)(4) and (5) are revised, and paragraph 
(h)(6) is added to read as follows:

[[Page 7998]]

Sec.  192.631  Control room management.

* * * * *
    (b) * * *
    (3) A controller's role during an emergency, even if the controller 
is not the first to detect the emergency, including the controller's 
responsibility to take specific actions and to communicate with others;
    (4) A method of recording controller shift-changes and any hand-
over of responsibility between controllers; and
    (5) The roles, responsibilities and qualifications of others with 
the authority to direct or supersede the specific technical actions of 
a controller.
* * * * *
    (h) * * *
    (4) Training that will provide a controller a working knowledge of 
the pipeline system, especially during the development of abnormal 
operating conditions;
    (5) For pipeline operating setups that are periodically, but 
infrequently used, providing an opportunity for controllers to review 
relevant procedures in advance of their application; and
    (6) Control room team training and exercises that include both 
controllers and other individuals, defined by the operator, who would 
reasonably be expected to operationally collaborate with controllers 
(control room personnel) during normal, abnormal or emergency 
situations. Operators must comply with the team training requirements 
under this paragraph by no later than January 23, 2018.
* * * * *

0
16. Section 192.740 is added to read as follows:


Sec.  192.740  Pressure regulating, limiting, and overpressure 
protection--Individual service lines directly connected to production, 
gathering, or transmission pipelines.

    (a) This section applies, except as provided in paragraph (c) of 
this section, to any service line directly connected to a production, 
gathering, or transmission pipeline that is not operated as part of a 
distribution system.
    (b) Each pressure regulating or limiting device, relief device 
(except rupture discs), automatic shutoff device, and associated 
equipment must be inspected and tested at least once every 3 calendar 
years, not exceeding 39 months, to determine that it is:
    (1) In good mechanical condition;
    (2) Adequate from the standpoint of capacity and reliability of 
operation for the service in which it is employed;
    (3) Set to control or relieve at the correct pressure consistent 
with the pressure limits of Sec.  192.197; and to limit the pressure on 
the inlet of the service regulator to 60 psi (414 kPa) gauge or less in 
case the upstream regulator fails to function properly; and
    (4) Properly installed and protected from dirt, liquids, or other 
conditions that might prevent proper operation.
    (c) This section does not apply to equipment installed on service 
lines that only serve engines that power irrigation pumps.

0
17. Section 192.1003 is revised to read as follows:


Sec.  192.1003  What do the regulations in this subpart cover?

    (a) General. Unless exempted in paragraph (b) of this section this 
subpart prescribes minimum requirements for an IM program for any gas 
distribution pipeline covered under this part, including liquefied 
petroleum gas systems. A gas distribution operator, other than a master 
meter operator or a small LPG operator, must follow the requirements in 
Sec. Sec.  192.1005 through 192.1013 of this subpart. A master meter 
operator or small LPG operator of a gas distribution pipeline must 
follow the requirements in Sec.  192.1015 of this subpart.
    (b) Exceptions. This subpart does not apply to an individual 
service line directly connected to a transmission, gathering, or 
production pipeline.

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
18. The authority citation for part 195 continues to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60116, 
60118, 60132, 60137, and 49 CFR 1.97.


0
19. In Sec.  195.2, add the definitions ``Confirmed discovery,'' ``In-
Line Inspection (ILI),'' ``In-Line Inspection Tool or Instrumented 
Internal Inspection Device,'' and ``Significant stress corrosion 
cracking'' in alphabetical order to read as follows:


Sec.  195.2  Definitions.

* * * * *
    Confirmed Discovery means when it can be reasonably determined, 
based on information available to the operator at the time a reportable 
event has occurred, even if only based on a preliminary evaluation.
* * * * *
    In-Line Inspection (ILI) means the inspection of a pipeline from 
the interior of the pipe using an in-line inspection tool. Also called 
intelligent or smart pigging.
    In-Line Inspection Tool or Instrumented Internal Inspection Device 
means a device or vehicle that uses a non-destructive testing technique 
to inspect the pipeline from the inside. Also known as intelligent or 
smart pig.
* * * * *
    Significant Stress Corrosion Cracking means a stress corrosion 
cracking (SCC) cluster in which the deepest crack, in a series of 
interacting cracks, is greater than 10% of the wall thickness and the 
total interacting length of the cracks is equal to or greater than 75% 
of the critical length of a 50% through-wall flaw that would fail at a 
stress level of 110% of SMYS.
* * * * *

0
20. In Sec.  195.3:
0
a. Add paragraph (b)(23);
0
b. Revise paragraph (c)(2);
0
c. Redesignate paragraphs (d) through (h) as (e) through (i) 
respectively and add a new paragraph (d); and
0
d. Amend newly redesignated paragraph (g) by adding paragraphs (g)(3) 
and (4); and
0
e. Revise newly redesignated paragraph (i)(1).
    The additions and revisions read as follows:


Sec.  195.3  Incorporation by reference.

* * * * *
    (b) * * *
    (23) API Standard 1163, ``In-Line Inspection Systems 
Qualification'' Second edition, April 2013, (API Std 1163), IBR 
approved for Sec.  195.591.
* * * * *
    (c) * * *
    (2) ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for Determining 
the Remaining Strength of Corroded Pipelines,'' 2004, (ASME/ANSI B31G), 
IBR approved for Sec. Sec.  195.452(h); 195.587; and 195.588(c).
* * * * *
    (d) American Society for Nondestructive Testing, P.O. Box 28518, 
1711 Arlingate Lane, Columbus, OH 43228. https://asnt.org.
    (1) ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection Personnel 
Qualification and Certification'' reapproved October 11, 2010, (ANSI/
ASNT ILI-PQ), IBR approved for Sec.  195.591.
    (2) [Reserved]
* * * * *
    (g) * * *
    (3) NACE SP0102-2010, ``Standard Practice, Inline Inspection of 
Pipelines'' revised March 13, 2010, (NACE SP0102), IBR approved for 
Sec.  195.591.
    (4) NACE SP0204-2008, ``Standard Practice, Stress Corrosion 
Cracking (SSC) Direct Assessment Methodology'' reaffirmed September 18, 
2008, (NACE SP0204), IBR approved for Sec.  195.588(c).
* * * * *

[[Page 7999]]

    (i) * * *
    (1) AGA Pipeline Research Committee, Project PR-3-805 ``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe,'' 
December 22, 1989, (PR-3-805 (RSTRING)). IBR approved for Sec. Sec.  
195.452(h); 195.587; and 195.588(c).
* * * * *

0
21. In Sec.  195.5, paragraph (d) is added to read as follows:


Sec.  195.5  Conversion to service subject to this part.

* * * * *
    (d) An operator converting a pipeline from service not previously 
covered by this part must notify PHMSA 60 days before the conversion 
occurs as required by Sec.  195.64.

0
22. In Sec.  195.52, paragraph (a) introductory text and paragraph (d) 
are revised to read as follows:


Sec.  195.52  Immediate notice of certain accidents.

    (a) Notice requirements. At the earliest practicable moment 
following discovery, of a release of the hazardous liquid or carbon 
dioxide transported resulting in an event described in Sec.  195.50, 
but no later than one hour after confirmed discovery, the operator of 
the system must give notice, in accordance with paragraph (b) of this 
section of any failure that:
* * * * *
    (d) New information. Within 48 hours after the confirmed discovery 
of an accident, to the extent practicable, an operator must revise or 
confirm its initial telephonic notice required in paragraph (b) of this 
section with a revised estimate of the amount of product released, 
location of the failure, time of the failure, a revised estimate of the 
number of fatalities and injuries, and all other significant facts that 
are known by the operator that are relevant to the cause of the 
accident or extent of the damages. If there are no changes or revisions 
to the initial report, the operator must confirm the estimates in its 
initial report.


Sec.  195.64  [Amended]

0
23. In Sec.  195.64, in paragraph (a), the term ``hazardous liquid'' is 
removed and replaced with the term ``hazardous liquid or carbon 
dioxide'' in the first sentence.

0
24. In Sec.  195.64, paragraph (c)(1)(ii) is revised and paragraphs 
(c)(1)(iii) and (iv) are added to read as follows:


Sec.  195.64  National Registry of Pipeline and LNG operators

* * * * *
    (c) * * *
    (1) * * *
    (ii) Construction of 10 or more miles of a new or replacement 
hazardous liquid or carbon dioxide pipeline;
    (iii) Reversal of product flow direction when the reversal is 
expected to last more than 30 days. This notification is not required 
for pipeline systems already designed for bi-directional flow; or
    (iv) A pipeline converted for service under Sec.  195.5, or a 
change in commodity as reported on the annual report as required by 
Sec.  195.49.
* * * * *

0
25. In Sec.  195.120, the section heading and paragraph (a) are revised 
to read as follows:


Sec.  195.120  Passage of In-Line Inspection tools.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each new pipeline and each replacement of line pipe, valve, fitting, or 
other line component in a pipeline must be designed and constructed to 
accommodate the passage of an In-Line Inspection tool, in accordance 
with NACE SP0102-2010, Section 7 (incorporated by reference, see Sec.  
195.3).
* * * * *

0
26. 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, Appendix A or Appendix B of API Std 1104 (incorporated 
by reference, see Sec.  195.3), or Section IX of the ASME Boiler and 
Pressure Vessel Code (ASME BPVC) (incorporated by reference, see Sec.  
195.3). The quality of the test welds used to qualify the welding 
procedures must be determined by destructive testing.
* * * * *

0
27. In Sec.  195.222, paragraph (a) is 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, Appendix A or Appendix B of API Std 1104 
(incorporated by reference, see Sec.  195.3), or section IX of the ASME 
Boiler and Pressure Vessel Code (ASME BPVC), (incorporated by 
reference, see Sec.  195.3) except that a welder or welding operator 
qualified under an earlier edition than listed in Sec.  195.3, may weld 
but may not requalify under that earlier edition.
* * * * *


Sec.  195.248  [Amended]

0
28. In Sec.  195.248, the phrase ``100 feet (30 millimeters)'' is 
removed and ``100 feet (30.5 meters)'' is added in its place in the 
table to paragraph (a).

0
29. In Sec.  195.446, revise paragraphs (b)(3) and (4), add paragraph 
(b)(5), revise paragraphs (h)(4) and (5), and add paragraph (h)(6) to 
read as follows:


Sec.  195.446  Control room management.

* * * * *
    (b) * * *
    (3) A controller's role during an emergency, even if the controller 
is not the first to detect the emergency, including the controller's 
responsibility to take specific actions and to communicate with others;
    (4) A method of recording controller shift-changes and any hand-
over of responsibility between controllers; and
    (5) The roles, responsibilities and qualifications of others who 
have the authority to direct or supersede the specific technical 
actions of controllers.
* * * * *
    (h) * * *
    (4) Training that will provide a controller a working knowledge of 
the pipeline system, especially during the development of abnormal 
operating conditions;
    (5) For pipeline operating setups that are periodically, but 
infrequently used, providing an opportunity for controllers to review 
relevant procedures in advance of their application; and
    (6) Control room team training and exercises that include both 
controllers and other individuals, defined by the operator, who would 
reasonably be expected to operationally collaborate with controllers 
(control room personnel) during normal, abnormal or emergency 
situations. Operators must comply with the team training requirements 
under this paragraph no later than January 23, 2018.
* * * * *

0
30. In Sec.  195.452, paragraph (a)(4) is added and paragraphs 
(c)(1)(i)(A) and (j)(5)(i) are revised to read as follows:


Sec.  195.452  Pipeline integrity management in high consequence areas.

    (a) * * *
    (4) Low stress pipelines as specified in Sec.  195.12.
* * * * *
    (c) * * *
    (1) * * *
    (i) * * *
    (A) In-Line Inspection tool or tools capable of detecting corrosion 
and deformation anomalies, including dents, gouges, and grooves. For 
pipeline segments that are susceptible to cracks

[[Page 8000]]

(pipe body and weld seams), an operator must use an in-line inspection 
tool or tools capable of detecting crack anomalies. When performing an 
assessment using an In-Line Inspection Tool, an operator must comply 
with Sec.  195.591;
* * * * *
    (j) * * *
    (5) * * *
    (i) In-Line Inspection tool or tools capable of detecting corrosion 
and deformation anomalies, including dents, gouges, and grooves. For 
pipeline segments that are susceptible to cracks (pipe body and weld 
seams), an operator must use an in-line inspection tool or tools 
capable of detecting crack anomalies. When performing an assessment 
using an In-Line Inspection tool, an operator must comply with Sec.  
195.591;
* * * * *

0
31. In Sec.  195.588, paragraph (a) is revised and paragraph (c) is 
added to read as follows:


Sec.  195.588  What standards apply to direct assessment?

    (a) If you use direct assessment on an onshore pipeline to evaluate 
the effects of external corrosion or stress corrosion cracking, you 
must follow the requirements of this section. This section does not 
apply to methods associated with direct assessment, such as close 
interval surveys, voltage gradient surveys, or examination of exposed 
pipelines, when used separately from the direct assessment process.
* * * * *
    (c) If you use direct assessment on an onshore pipeline to evaluate 
the effects of stress corrosion cracking, you must develop and follow a 
Stress Corrosion Cracking Direct Assessment plan that meets all 
requirements and recommendations of NACE SP0204-2008 (incorporated by 
reference, see Sec.  195.3) and that implements all four steps of the 
Stress Corrosion Cracking Direct Assessment process including pre-
assessment, indirect inspection, detailed examination and post-
assessment. As specified in NACE SP0204-2008, Section 1.1.7, Stress 
Corrosion Cracking Direct Assessment is complementary with other 
inspection methods such as in-line inspection or hydrostatic testing 
and is not necessarily an alternative or replacement for these methods 
in all instances. In addition, the plan must provide for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data to identify 
whether the conditions for stress corrosion cracking are present and to 
prioritize the segments for assessment in accordance with NACE SP0204-
2008, Sections 3 and 4, and Table 1. This process must also include 
gathering and evaluating data related to SCC at all sites an operator 
excavates during the conduct of its pipeline operations (both within 
and outside covered segments) where the criteria in NACE SP0204-2008 
indicate the potential for Stress Corrosion Cracking Direct Assessment. 
This data gathering process must be conducted in accordance with NACE 
SP0204-2008, Section 5.3, and must include, at a minimum, all data 
listed in NACE SP0204-2008, Table 2. Further, an operator must analyze 
the following factors as part of this evaluation:
    (i) The effects of a carbonate-bicarbonate environment, including 
the implications of any factors that promote the production of a 
carbonate-bicarbonate environment such as soil temperature, moisture, 
factors that affect the rate of carbon dioxide generation, and/or 
cathodic protection.
    (ii) The effects of cyclic loading conditions on the susceptibility 
and propagation of SCC in both high-pH and near-neutral-pH 
environments.
    (iii) The effects of variations in applied cathodic protection such 
as overprotection, cathodic protection loss for extended periods, and 
high negative potentials.
    (iv) The effects of coatings that shield cathodic protection when 
disbonded from the pipe.
    (v) Other factors that affect the mechanistic properties associated 
with SCC including but not limited to operating pressures, high tensile 
residual stresses, and the presence of sulfides.
    (2) Indirect inspection. In addition to the requirements and 
recommendations of NACE SP0204-2008, Section 4, the plan's procedures 
for indirect inspection must include provisions for conducting at least 
two different, but complementary, indirect assessment electrical 
surveys, and the basis on the selections as the most appropriate for 
the pipeline segment based on the data gathering and integration step.
    (3) Direct examination. In addition to the requirements and 
recommendations of NACE SP0204-2008, Section 5, the plan's procedures 
for direct examination must provide for conducting a minimum of four 
direct examinations within the SCC segment at locations determined to 
be the most likely for SCC to occur.
    (4) Remediation and mitigation. If any indication of SCC is 
discovered in a segment, an operator must mitigate the threat in 
accordance with one of the following applicable methods:
    (i) Non-significant SCC, as defined by NACE SP0204-2008, may be 
mitigated by either hydrostatic testing in accordance with paragraph 
(b)(4)(ii) of this section, or by grinding out with verification by 
Non-Destructive Examination (NDE) methods that the SCC defect is 
removed and repairing the pipe. If grinding is used for repair, the 
remaining strength of the pipe at the repair location must be 
determined using ASME/ANSI B31G or RSTRENG (incorporated by reference, 
see Sec.  195.3) and must be sufficient to meet the design requirements 
of subpart C of this part.
    (ii) Significant SCC must be mitigated using a hydrostatic testing 
program with a minimum test pressure between 100% up to 110% of the 
specified minimum yield strength for a 30-minute spike test immediately 
followed by a pressure test in accordance with subpart E of this part. 
The test pressure for the entire sequence must be continuously 
maintained for at least 8 hours, in accordance with subpart E of this 
part. Any test failures due to SCC must be repaired by replacement of 
the pipe segment, and the segment retested until the pipe passes the 
complete test without leakage. Pipe segments that have SCC present, but 
that pass the pressure test, may be repaired by grinding in accordance 
with paragraph (c)(4)(i) of this section.
    (5) Post assessment. In addition to the requirements and 
recommendations of NACE SP0204-2008, sections 6.3, periodic 
reassessment, and 6.4, effectiveness of Stress Corrosion Cracking 
Direct Assessment, the plan's procedures for post assessment must 
include development of a reassessment plan based on the susceptibility 
of the operator's pipe to Stress Corrosion Cracking as well as on the 
behavior mechanism of identified cracking. Factors to be considered 
include, but are not limited to:
    (i) Evaluation of discovered crack clusters during the direct 
examination step in accordance with NACE SP0204-2008, sections 5.3.5.7, 
5.4, and 5.5;
    (ii) Conditions conducive to creation of the carbonate-bicarbonate 
environment;
    (iii) Conditions in the application (or loss) of cathodic 
protection that can create or exacerbate SCC;
    (iv) Operating temperature and pressure conditions;
    (v) Cyclic loading conditions;
    (vi) Conditions that influence crack initiation and growth rates;

[[Page 8001]]

    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and
    (ix) Disbonded coatings that shield CP from the pipe.

0
32. Section 195.591 is added to read as follows:


Sec.  195.591  In-Line inspection of pipelines.

    When conducting in-line inspection of pipelines required by this 
part, each operator must comply with the requirements and 
recommendations of API Std 1163, Inline Inspection Systems 
Qualification Standard; ANSI/ASNT ILI-PQ, Inline Inspection Personnel 
Qualification and Certification; and NACE SP0102-2010, Inline 
Inspection of Pipelines (incorporated by reference, see Sec.  195.3). 
An in-line inspection may also be conducted using tethered or remote 
control tools provided they generally comply with those sections of 
NACE SP0102-2010 that are applicable.

PART 199--DRUG AND ALCOHOL TESTING

0
33. The authority citation for part 199 continues to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60117, and 
60118; 49 CFR 1.97.


0
34. In Sec.  199.105, paragraph (b) is revised to read as follows:


Sec.  199.105  Drug tests required.

* * * * *
    (b) Post-accident testing. (1) As soon as possible but no later 
than 32 hours after an accident, an operator must drug test each 
surviving covered employee whose performance of a covered function 
either contributed to the accident or cannot be completely discounted 
as a contributing factor to the accident. An operator may decide not to 
test under this paragraph but such a decision must be based on specific 
information that the covered employee's performance had no role in the 
cause(s) or severity of the accident.
    (2) If a test required by this section is not administered within 
the 32 hours following the accident, the operator must prepare and 
maintain its decision stating the reasons why the test was not promptly 
administered. If a test required by paragraph (b)(1) of this section is 
not administered within 32 hours following the accident, the operator 
must cease attempts to administer a drug test and must state in the 
record the reasons for not administering the test.
* * * * *

0
35. In Sec.  199.117, paragraph (a)(5) is added to read as follows:


Sec.  199.117  Recordkeeping.

    (a) * * *
    (5) Records of decisions not to administer post-accident employee 
drug tests must be kept for at least 3 years.
* * * * *

0
36. In Sec.  199.119, paragraphs (a) and (b) are revised to read as 
follows:


Sec.  199.119  Reporting of anti-drug testing results.

    (a) Each large operator (having more than 50 covered employees) 
must submit an annual Management Information System (MIS) report to 
PHMSA of its anti-drug testing using the MIS form and instructions as 
required by 49 CFR part 40 (at Sec.  40.26 and appendix H to part 40), 
not later than March 15 of each year for the prior calendar year 
(January 1 through December 31). The Administrator may require by 
notice in the PHMSA Portal (https://portal.phmsa.dot.gov/phmsaportallanding) that small operators (50 or fewer covered 
employees), not otherwise required to submit annual MIS reports, to 
prepare and submit such reports to PHMSA.
    (b) Each report required under this section must be submitted 
electronically at http://damis.dot.gov. An operator may obtain the user 
name and password needed for electronic reporting from the PHMSA Portal 
(https://portal.phmsa.dot.gov/phmsaportallanding). If electronic 
reporting imposes an undue burden and hardship, the operator may submit 
a written request for an alternative reporting method to the 
Information Resources Manager, Office of Pipeline Safety, Pipeline and 
Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., 
Washington, DC 20590. The request must describe the undue burden and 
hardship. PHMSA will review the request and may authorize, in writing, 
an alternative reporting method. An authorization will state the period 
for which it is valid, which may be indefinite. An operator must 
contact PHMSA at 202-366-8075, or electronically to 
informationresourcesmanager@dot.gov to make arrangements for submitting 
a report that is due after a request for alternative reporting is 
submitted but before an authorization or denial is received.
* * * * *

0
37. In Sec.  199.225, the introductory text and paragraph (a)(1) are 
revised to read as follows:


Sec.  199.225  Alcohol tests required.

    Each operator must conduct the following types of alcohol tests for 
the presence of alcohol:
    (a) * * *
    (1) As soon as practicable following an accident, each operator 
must test each surviving covered employee for alcohol if that 
employee's performance of a covered function either contributed to the 
accident or cannot be completely discounted as a contributing factor to 
the accident. The decision not to administer a test under this section 
must be based on specific information that the covered employee's 
performance had no role in the cause(s) or severity of the accident.
* * * * *

0
38. In Sec.  199.227, paragraph (b)(4) is added to read as follows:


Sec.  199.227  Retention of records.

* * * * *
    (b) * * *
    (4) Three years. Records of decisions not to administer post-
accident employee alcohol tests must be kept for a minimum of three 
years.
* * * * *

0
39. In Sec.  199.229, paragraphs (a) and (c) are revised as follows:


Sec.  199.229  Reporting of alcohol testing results.

    (a) Each large operator (having more than 50 covered employees) 
must submit an annual MIS report to PHMSA of its alcohol testing 
results using the MIS form and instructions as required by 49 CFR part 
40 (at Sec.  40.26 and appendix H to part 40), not later than March 15 
of each year for the prior calendar year (January 1 through December 
31). The Administrator may require by notice in the PHMSA Portal 
(https://portal.phmsa.dot.gov/phmsaportallanding) that small operators 
(50 or fewer covered employees), not otherwise required to submit 
annual MIS reports, to prepare and submit such reports to PHMSA.
* * * * *
    (c) Each report required under this section must be submitted 
electronically at http://damis.dot.gov. An operator may obtain the user 
name and password needed for electronic reporting from the PHMSA Portal 
(https://portal.phmsa.dot.gov/phmsaportallanding). If electronic 
reporting imposes an undue burden and hardship, the operator may submit 
a written request for an alternative reporting method to the 
Information Resources Manager, Office of Pipeline Safety, Pipeline and 
Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., 
Washington, DC 20590. The request must describe the undue burden and 
hardship. PHMSA will review the request and may authorize, in writing, 
an alternative

[[Page 8002]]

reporting method. An authorization will state the period for which it 
is valid, which may be indefinite. An operator must contact PHMSA at 
202-366-8075, or electronically to informationresourcesmanager@dot.gov 
to make arrangements for submitting a report that is due after a 
request for alternative reporting is submitted but before an 
authorization or denial is received.
* * * * *

    Issued in Washington, DC, on December 22, 2016, under authority 
delegated in 49 CFR Part 1.97.
Marie Therese Dominguez,
Administrator.
[FR Doc. 2016-31461 Filed 1-19-17; 8:45 am]
BILLING CODE 4910-60-P


