Pipeline Safety: Operator Qualification, Cost Recovery, Accident and Incident Notification, and Other Pipeline Safety Proposed Changes, 39915-39939 [2015-16264]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 80, Number 132 (Friday, July 10, 2015)]
[Proposed Rules]
[Pages 39915-39939]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-16264]



[[Page 39915]]

Vol. 80

Friday,

No. 132

July 10, 2015

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, et al.





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

Federal Register / Vol. 80 , No. 132 / Friday, July 10, 2015 / 
Proposed Rules

[[Page 39916]]


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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]
RIN 2137-AE94


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

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

ACTION: Notice of proposed rulemaking.

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SUMMARY: PHMSA is proposing amendments to 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 proposing 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 for submitters of information to request 
PHMSA keep the information confidential. We are also proposing changes 
to the operator qualification (OQ) requirements and drug and alcohol 
testing requirements and incorporating consensus standards by reference 
for in-line inspection (ILI) and Stress Corrosion Cracking Direct 
Assessment (SCCDA).

DATES: Submit comments by September 8, 2015.

ADDRESSES: Comments should reference Docket No. PHMSA-2013-0163 and may 
be submitted in the following ways:
     E-Gov Web site: https://www.regulations.gov. This Web site 
allows the public to enter comments on any Federal Register notice 
issued by any agency. Follow the instructions for submitting comments.
     Fax: 202-493-2251.
     Mail: Docket Management System: U.S. Department of 
Transportation (DOT), Docket Operations, M-30, Room W12-140, 1200 New 
Jersey Avenue SE., Washington, DC 20590-0001.
     Hand Delivery: DOT Docket Management System, West Building 
Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 
20590-0001 between 9:00 a.m. and 5:00 p.m., Monday through Friday, 
except Federal holidays.
    Instructions: If you submit your comments by mail, please submit 
two copies. To receive confirmation that PHMSA received your comments, 
include a self-addressed stamped postcard.

    Note: Comments are posted without changes or edits to https://www.regulations.gov, including any personal information provided. 
There is a privacy statement published on https://www.regulations.gov.

Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act Statement 
published in the Federal Register on April 11, 2000 (70 FR 19477), or 
visit https://dms.dot.gov.

FOR FURTHER INFORMATION CONTACT: Tewabe Asebe by telephone at 202-366-
5523 or by email at Tewabe.Asebe@dot.gov.

SUPPLEMENTARY INFORMATION: 

Executive Summary

A. Purpose of the Regulatory Action (Statement of Need)

    The purpose of this proposed 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). The proposal associated with section 9 would limit the 
accident and incident reporting requirements to within one hour. PHMSA 
expects that quicker accident and incident reporting would lead to a 
safety benefit to the public, the environment, and limit property 
damage. The proposal associated with section 13 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. PHMSA is also proposing to expand the 
existing Operator Qualification (OQ) scope to cover new construction 
and certain other currently uncovered tasks, require operators use 
trained and qualified individuals when performing new construction 
work, and add program effectiveness requirements for operators to gauge 
the effectiveness of the OQ programs. PHMSA believes that requiring 
operators to use trained and qualified individuals would decrease human 
errors. PHMSA is also proposing to provide a renewal procedure for 
expiring special permits and proposing other minor and administrative 
changes. The proposed changes 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;
     Expanding the existing Operator Qualification (OQ) scope 
to cover new construction and previously excluded operation and 
maintenance tasks, addressing the National Transportation Safety 
Board's (NTSB) recommendation to clarify OQ requirements for control 
rooms, and extending the requirements to operators of Type A gathering 
lines in Class 2 locations and Type B onshore gas gathering lines;
     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 permanent 
reversal of flow that lasts more than 30 days or a change in product 
(e.g., from liquid to gas, from crude oil to highly volatile liquids 
(HVL));
     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 three years a record of the reason why post-
accident drug and alcohol test was not conducted;
     Adding a procedure to request PHMSA keep submitted 
information confidential;
     Adding reference to Appendix B of API 1104 related to in-
service welding in parts 192 and 195; and
     Aaking minor editorial corrections.

[[Page 39917]]

B. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

    Several of the proposed changes would address sections 9 and 13 of 
the 2011 Act, which was signed into law on January 3, 2012. (Pub. L. 
112-90). Section 9 of the 2011 Act requires PHMSA to specify a time 
limit for telephonic or electronic reporting of pipeline accidents and 
incidents. Section 13 of the 2011 Act (codified at 49 U.S.C. 60117) 
allows PHMSA to prescribe a fee structure and assessment methodology to 
recover costs associated with design reviews.

C. Costs and Benefits

    PHMSA has estimated annual compliance costs at $3.1 million; less 
savings to be realized from the removal of farm taps from the DIMP 
requirements. Annual safety benefits cannot be quantified as readily 
due to data limitations, but are expected to be $1.6 million per year 
in avoided incident costs, plus numerous intangible benefits from the 
improved clarity and consistency of regulations and required post-
incident drug and alcohol test decision justification. Although the 
quantified benefits do not exceed the estimated costs, PHMSA believes 
that these non-quantified benefits are significant enough to outweigh 
the costs of compliance. PHMSA believes that updating regulations, 
providing clarification, and providing methods for assessment tools by 
incorporating consensus standards all help to improve compliance with 
pipeline safety regulations and to reduce the likelihood of a serious 
pipeline incident. In particular, proposed operator qualification 
provisions ensure that pipeline construction personnel and operations 
and maintenance personnel have the appropriate skills for the functions 
they are performing. This would reduce the likelihood of human error-
related incidents. At an annual compliance cost of $3.1 million, the 
proposed changes would be cost effective if they prevented a single 
fatal incident over a three-year period.

I. Accident and Incident Notification

Summary

    This proposed rulemaking action would 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.

Background

    PHMSA requires pipeline owners and operators to notify the National 
Response Center (NRC) by telephone or electronically at the earliest 
practicable moment following discovery of an incident or accident 
(Sec. Sec.  191.5 and 195.52). In an advisory bulletin published on 
September 6, 2002; 67 FR 57060, PHMSA advised owners and operators of 
gas and hazardous liquids pipeline systems and liquefied natural gas 
(LNG) facilities that reporting at the earliest practicable opportunity 
usually means one to two hours after discovery of the incident.

Justification for the Recommended Change

    On January 3, 2012, President Obama signed into law the 2011 Act. 
Section 9 of the 2011 Act directs PHMSA to require pipeline operators 
to make incident/accident telephonic notifications at the earliest 
practicable moment following confirmed discovery of an accident or 
incident and not later than 1 hour following the time of such confirmed 
discovery.
    PHMSA proposes to revise the 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 the confirmed discovery of an 
accident or incident, but not later than one hour following the time of 
such confirmed discovery. Further, we are proposing to require 
operators to revise or confirm that initial notification within 48 
hours of confirmed discovery of the accident or incident. Prompt 
reporting of a pipeline incident to the NRC is crucial to Federal 
investigators' ability to investigate and resolve pipeline safety 
concerns. Once a report is made, investigators must decide at the 
outset whether a full Federal investigation is necessary. Failure to 
report promptly hinders the decision making process and could 
jeopardize the outcome of any subsequent investigation and threaten 
public safety. Delays in reporting caused by an operator waiting until 
the operator definitely determines an event meets the reporting 
criteria would defeat a fundamental purpose of the 2011 Act, which is 
to give PHMSA and other agencies the earliest opportunity to assess 
whether an immediate response to a pipeline incident is needed.
    As demonstrated by PHMSA's past enforcement actions, ``discovery'' 
has been evaluated on a case-by-case basis considering the totality of 
the circumstances. Because the statute requires reporting after 
``confirmed discovery,'' PHMSA proposes to define the term in 
Sec. Sec.  191.3 and 195.2 as ``when there is sufficient information to 
determine that a reportable event has occurred even if an evaluation 
has not been completed.'' After a more thorough investigation, the 
operator can submit more detailed information in the written incident 
report. This policy of erring on the side of caution ensures that 
delays in reporting incidents would be avoided. PHMSA seeks comment on 
the proposed definition of ``confirmed discovery'' and how it would 
affect operators in their evaluation of an incident or accident. In 
particular, PHMSA is interested in alternative definitions of 
``confirmed discovery'' (e.g., if an operator were to receive two 
different notifications that validate each other) and the advantages 
the alternative definitions have over the proposed definition.

II. Cost Recovery for Design Reviews

Summary

    This proposed rulemaking action would 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 either overall design and 
construction costs totaling at least $2,500,000,000 or that contain new 
and novel technologies.

Background

    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 issued guidance in January 2013, on its Web site to clarify 
the meaning of the term ``new or novel technologies or design'' as 
meaning, ``any products, designs, materials, testing, construction, 
inspection, or operational procedures that are not addressed in title 
49 Code of Federal Regulations (CFR) parts 192, 193, or 195 due to 
technology or design advances and innovation.'' PHMSA developed this 
definition to include any technologies that are developed or have 
existed and are being adopted widely due to developments other than 
technology or innovation.

Justification for the Recommended Changes

    PHMSA conducts facility design safety reviews in connection with

[[Page 39918]]

proposals to construct, expand, or operate gas or hazardous liquid 
pipelines or liquefied natural gas pipeline facilities. Reviews include 
design, construction, and operational inspections and oversight. These 
reviews divert a significant amount of PHMSA's limited resources from 
the agency's pipeline safety enforcement responsibilities.
    While PHMSA's pipeline account is funded entirely by user fees on 
the pipeline industry, PHMSA does not currently recover costs incurred 
specifically while conducting these reviews for pipeline operators. 
Section 13 of the 2011 Act permits PHMSA to require the entity or 
individual proposing the project to pay the costs incurred by PHMSA 
relating to such reviews.
    Historically, PHMSA's pipeline safety costs associated with new 
pipeline design and construction reviews and inspections have been paid 
for through Pipeline User Fee collections. As major pipeline 
construction projects increase, PHMSA's inspection hours and costs have 
increased on major projects, diverting resources away from other Agency 
priorities. In this NPRM PHMSA is taking the first step in proposing to 
exercise the cost recovery authority described in Section 13(a) of the 
2011 Act by prescribing a fee structure and assessment methodology that 
is based on the costs of providing these reviews that are initiated by 
the pipeline operator. However, in terms of budgetary scoring, Section 
13 allows for the collection of the fee as a mandatory receipt. 
However, the Administration would like to use these fees as an offset 
for discretionary spending, and as such, PHMSA has proposed that 
appropriations language in the last several Budgets to make this a 
discretionary offsetting fee. Neither the Consolidated Appropriations 
Act of 2014 nor the Consolidated and Further Continuing Appropriations 
Act of 2015 enacted language that would make this a discretionary 
offsetting fee. Hence, PHMSA is proposing this portion of the ANPRM 
under the assumption that Congress will enact a revision to make this a 
discretionary offsetting fee before PHMSA would issue a final rule to 
implement the fee.
    PHMSA believes that a review of a large project or new technology 
that has safety benefits in quality control would drain the agency's 
resources without any cost recovery mechanism. PHMSA has developed a 
sample master cost recovery agreement that would be used between PHMSA 
and the applicant for a project proposal meeting the criteria of 
proposed 49 CFR part 190, subpart D requirements. The sample master 
cost recovery agreement will be posted on PHMSA's Web site and in 
Docket No. PHMSA-2013-0163. A master cost recovery agreement would 
include at a minimum:
    (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;
    (7) Provisions for terminating the agreement; and
    (8) A project reimbursement cost schedule based upon the project 
timing and scope.

III. Operator Qualification Requirements

Summary

    This proposed rulemaking action would amend the Federal pipeline 
safety regulations in 49 CFR parts 192 and 195 relative to operator 
qualification requirements. The amendments would include: Expanding the 
scope of OQ requirements to cover new construction and certain 
previously excluded operation and maintenance tasks, extending the OQ 
requirements to operators of Type A gas gathering lines in Class 2 
locations, Type B onshore gas gathering lines, and regulated rural 
hazardous liquid gathering lines, requiring a program effectiveness 
review, and adding new recordkeeping requirements. The proposed changes 
would enhance the OQ requirements by clarifying existing requirements 
and addressing NTSB recommendation to extend operator qualification 
requirements to control center staff involved in pipeline operational 
decisions (Safety Recommendation P-12-8).

Background

    Sections 101 and 201 of the Pipeline Safety Reauthorization Act of 
1988 (Pub. L. 100-561; October 31, 1988) authorize PHMSA to require all 
individuals responsible for the operation and maintenance of pipeline 
facilities to be tested for qualifications and to be certified to 
perform such functions. PHMSA published a final rule on August 27, 
1999; 64 FR 46853 for the qualification of pipeline personnel.
1. Public Meeting
    Over 650 individuals from various stakeholder groups attended 
PHMSA's public meeting on OQ History and Milestones in January 2003 in 
San Antonio, Texas to discuss gaps between the OQ rule and actual 
operations in the field.
2. ASME Standard
    ASME standard, ASME B31Q (``Pipeline Personnel Qualification'') was 
revised in October 2010, to address many OQ issues identified at the 
public meeting. An OQ team reviewed the standard in detail and 
determined that while the standard provided detailed guidance in most 
areas, PHMSA should instead amend the current regulation to address 
areas that had not been addressed in the revised ASME standard.\1\
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    \1\ The OQ team consists of members from PHMSA and several State 
pipeline safety agencies.
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3. NTSB Recommendation
    The NTSB issued the following safety recommendation to PHMSA on 
July 25, 2012, (P-12-8):

    Extend operator qualification requirements in Title 49 Code of 
Federal Regulations Part 195 Subpart G to all hazardous liquid and 
gas transmission control center staff involved in pipeline 
operational decisions.

    Although our existing Control Room Frequently Asked Questions 
(B.01, B.03 & B.05) (https://primis.phmsa.dot.gov/crm/faqs.htm) all 
touch on the topic of supervisors or others intervening in control room 
operations, there are no specific OQ program requirements. Therefore, 
PHMSA is proposing explicit control room team training requirement for 
all individuals who would be reasonably expected to interface with 
controllers during normal, abnormal or emergency situations in 
Sec. Sec.  192.631(h) and 195.446(h).
4. Gathering Lines
    PHMSA issued a final rule on March 15, 2006; 71 FR 13289 that 
revises the methodology used to identify regulated onshore gas 
gathering lines and implemented a tiered compliance approach to address 
potential risk. In a final rule issued on June 3, 2008; 73 FR 31634, 
PHMSA defined the criteria to identify a regulated onshore hazardous 
liquid gathering line. In both instances, PHMSA allowed a modified 
approach for recordkeeping, requiring only a description of the 
processes used to

[[Page 39919]]

qualify personnel instead of a description of qualification methods for 
each individual who is allowed to perform tasks on Type A gas gathering 
lines in Class 2 locations or regulated hazardous liquids gathering 
lines in rural locations. PHMSA has determined that this approach fails 
to ensure that individuals possess the requisite knowledge, skills, and 
abilities to perform the actual work. Additionally, in the March 2006 
rulemaking, PHMSA subjected operators of Type B onshore gas gathering 
lines to a very limited set of required compliance activities, 
excluding and OQ requirements. Having a properly trained and qualified 
workforce is necessary and paramount to perform work on any category of 
pipeline and to solidify a consistent application of OQ across all 
sectors of pipeline transportation.
5. Control Room Team Training
    NTSB issued the following safety recommendation to PHMSA on July 
25, 2012, (P-12-7):

    Develop requirements for team training of control center staff 
involved in pipeline operations similar to those used in other 
transportation modes.

    Although not an explicit requirement, a number of the sections in 
the Control Room Management regulations, along with the inspection 
guidance and related Frequently Asked Questions, already touch on the 
concept of team training for control room personnel and others who 
would likely work together as a team during normal, abnormal, and 
emergency situations. PHMSA believes a requirement for control room 
team training would better prepare all individuals who would be 
reasonably expected to interface with controllers (control room 
personnel) during normal, abnormal or emergency situations. While the 
CRM regulations call out certain specific individuals such as 
controllers, supervisors, and field personnel, understanding of the 
requirements of CRM 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, as recommended by NTSB, PHMSA is 
proposing to require control room team training in Sec. Sec.  
192.631(h) and 195.446(h).

Justification for the Proposed Changes

    The industry standard, ASME B31Q, Pipeline Personnel Qualification, 
defines covered task as ``those tasks that can affect the safety or 
integrity of the pipeline''.
    The current rule is not prescriptive and the resulting flexibility 
built into the performance-based rule makes it difficult to measure 
operator's compliance with the rule. Under the current regulation, a 
covered task is an activity, defined by the operator that meets the 4-
part test:
    (1) Is performed on a pipeline facility;
    (2) Is an operations or maintenance task;
    (3) Is performed as a requirement of this part; and
    (4) Affects the operation or integrity of the pipeline.
    Many of the pipeline safety regulations are performance based, 
rather than prescriptive requirements. The OQ regulations require 
operators to identify covered tasks for all of their operations and 
maintenance activities that are required by parts 192 and 195, 
regardless of whether such activities arise from performance-based 
regulations or from more prescriptive requirements. It's the operator's 
responsibility to identify their unique and specific tasks and 
terminology in both their operations and maintenance documentation, as 
well as ensure these tasks are covered tasks in the Operator 
Qualification Program.
    Many O&M tasks (part 2 of the 4-part test) that an operator 
performs are not specifically called out in the regulation (part 3 of 
the 4-part test).
    Performance based tasks may include activities, such as those 
involved in making repairs (while repairs are called out as a 
requirement of the regulations, specific terminology such as mud 
plugging, pipefitting, installing Clockspring, etc. associated with 
making repairs is not). Making pipeline repairs in a safe manner 
involves myriad tasks that may vary from one job to another and from 
one operator to another. While the current performance based 
regulations provide flexibility for each operator to identify those 
particular repair tasks, the proposed rule to define covered tasks is 
clearer and helps to eliminate confusion over whether performance based 
tasks are ``performed as a requirement of this part.'' Most of the 
proposed OQ changes are not significant because the existing sections 
are renumbered or combined with other sections. However, this proposed 
rule includes two new requirements: (1) Includes OQ requirements for 
new constructions by changing the Scope; and (2) adds a new program 
effectiveness requirement to ensure that operators complete a review of 
the effectiveness of their OQ program. PHMSA's proposed changes to the 
OQ rule at parts 192 and 195 are as follows:
    1. Change the scope of the OQ rule in Sec. Sec.  192.801 and 
195.501 to revise the method of determining a ``covered task.'' Instead 
of determining a covered task by the ``4-part test,'' PHMSA is 
proposing to define a covered task as any maintenance, construction or 
emergency response task the operator identifies as affecting the safety 
or integrity of the pipeline facility. The ``4-part test'' omitted 
important tasks, such as all construction tasks on new pipelines and 
certain operation and maintenance tasks.
    2. Update the ``General'' sections of Sec. Sec.  192.809 and 
195.509 to remove the implementation dates that no longer affect the 
implementation requirements for operators. In addition, after they are 
updated Sec. Sec.  192.809 and 195.509 are renumbered as Sec. Sec.  
192.805 and 195.505.
    3. Change the requirements in Sec. Sec.  192.805 and 195.505 by 
adding new definitions, deleting an obsolete date for training 
requirements and clarify the need for training individuals performing 
covered tasks. Additionally, we are adding a new requirement for 
evaluators of individuals performing covered tasks, including training 
requirements for new construction tasks as the current OQ requirements 
do not include new construction tasks.
    4. Add a ``Program Effectiveness'' requirement at Sec. Sec.  
192.807 and 195.507 to ensure that operators complete a review of the 
effectiveness of their OQ program. The review would include ensuring 
that procedures that were amended have been captured in the necessary 
portions of the OQ program.
    5. Add record requirements in Sec. Sec.  192.809 and 195.509 that 
are normally reviewed during the inspection of OQ programs and are 
necessary to provide a thorough overview of an OQ program. The 
additional records would include records that document evaluators' 
performance and program effectiveness.
    6. Add a new paragraph (b)(5) to Sec. Sec.  192.631 and 195.446 to 
require each

[[Page 39920]]

operator to define the roles and responsibilities and qualifications of 
others who have the authority to direct or supersede the specific 
technical actions of controllers. PHMSA believes this change would 
reinforce that operators need to declare the roles, responsibilities, 
and qualifications of all others who, at times, could intervene in 
control room operations.
    7. Add a new subparagraph in the ``Qualification Program'' sections 
as Sec. Sec.  192.805(b)(7) and 195.505(b)(7) proposing requirements 
addressing management of change and the communication of those changes. 
This proposed section would ensure that weaknesses of a program are 
found and corrections are made with notification to those affected, and
    8. Modify Sec. Sec.  192.9 and 195.11 to require operators to 
establish and administer an OQ program covering personnel who perform 
work on Type A gas gathering lines in Class 2 locations, regulated Type 
B onshore gas gathering lines and regulated hazardous liquids gathering 
lines in rural locations.

IV. Special Permit Renewal

Summary

    This proposed rulemaking action would amend Sec.  190.341 of the 
Federal pipeline safety regulations to add procedures for renewing a 
special permit.

Background and Justification

    As defined in Sec.  190.341(a), a special permit is an order by 
which PHMSA waives compliance with one or more of the pipeline safety 
regulations if it determines that granting the permit would ``not be 
inconsistent with pipeline safety.'' Special permits are authorized by 
statute in 49 U.S.C. 60118(c), and the application process is set forth 
in Sec.  190.341. 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 is committed to 
public involvement and transparency in special permit proceedings and 
publishes notice of every special permit application received in the 
Federal Register for comment.
    In the past, PHMSA has included an expiration date for certain 
special permits depending on the nature of the permit. By doing so, 
PHMSA is able to ensure that these special permits will be reviewed 
again no later than the expiration date. This process ensures that a 
special permit will not continue to be used if it is no longer in the 
best interest of public safety.
    PHMSA is proposing to add a renewal procedure to the pipeline 
safety regulations for those Special Permits that have expiration 
dates. This special permit renewal procedure will ensure the permit 
conditions are still valid for the pipeline and if changes and updates 
are required to maintain safety and the environment.

V. Farm Taps

Summary

    This proposed rulemaking action would amend 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).

Background

    On October 29, 2012, PHMSA received a request from the Interstate 
Natural Gas Association of America (INGAA), asking if PHMSA covers the 
farm tap issue on the upcoming miscellaneous issue rulemaking. In 
addition, PHMSA received a February 15, 2013, written letter from the 
National Association of Pipeline Safety Representatives (NAPSR) 
requesting an exemption of farm taps from the DIMP requirements as 
follows:
    The letter requested PHMSA to take the following actions relative 
to the applicability of DIMP to ``Farm Taps'':
    1. Amend the applicable part 192 sections to exempt those pipelines 
commonly referred to as ``farm taps'' (a term originating from industry 
jargon) from the requirements of Subpart P, Gas Distribution Pipeline 
Integrity Management; and
    2. Amend part 192 to include periodic inspection requirements in a 
new section covering ``pressure regulating and over-pressure-relief 
equipment'' on a pipeline that originates from a transmission, 
gathering, or production pipeline that serves a service line.
    In support of the above, NAPSR offered the following:
     Farm taps are distribution service lines per Sec.  192.3 ;
     During the DIMP rulemaking, little consideration was given 
to the potential impact or appropriateness of subjecting farm taps to 
DIMP;
     The risk to the public from a failure on a farm tap is 
generally lower in Class 1 and Class 2 locations in which farm taps are 
typically located and operated;
     Currently the regulator and relief equipment with farm 
taps are not subject to over pressurization protection requirements 
associated with pressure limiting stations.
    This proposal originated with the NAPSR DIMP Implementation Task 
Force and was subsequently approved by the NAPSR Board in January 2013.
    As NAPSR described it, ``farm tap'' is industry jargon for a 
pipeline that branches from a transmission, gathering, or production 
pipeline to deliver gas to a farmer or other landowner. Historically, 
PHMSA and its predecessor agencies have held that farm taps are service 
lines--a subset of distribution pipelines. Rulemaking proceedings and 
responses to requests for interpretation have recognized this dating as 
far back as 1971.
    On December 4, 2009, PHMSA published the DIMP final rule (74 FR 
63906) for gas distribution pipelines. That rule applies IM 
requirements to all distribution pipelines. Unlike the IM requirements 
for hazardous liquid or gas transmission pipelines, the DIMP 
requirements do not focus on a subset of pipelines in ``high 
consequence areas,'' but instead apply to all distribution pipelines, 
including farm taps.

Justification for the Recommended Changes

    Farm taps are mostly located in less-populated areas (Class 1 and 2 
locations). The risk to the public from farm taps is generally low, but 
the risk is dependent upon the service line in which the farm tap is 
employed, the environment in which it operates, and the consequence of 
an overpressurization event. DIMP is written to identify needed risk 
control practices for threats associated with distribution systems, 
whereas threats to typical farm taps are limited, and most are already 
addressed within part 192. Therefore, in response to the INGAA and 
NAPSR requests, PHMSA is proposing to amend part 192 to exempt farm 
taps from the requirements of part 192, subpart P--Gas Distribution 
Pipeline Integrity Management. However, to better protect customers 
served by these lines, PHMSA is proposing to amend part 192, subpart 
M--Maintenance by adding a new section that prescribes inspection 
activities under the existing States and Federal pipeline safety 
inspection programs for pressure regulators and overpressurization 
protection equipment on service lines that originate from transmission, 
gathering, or production pipelines. Currently, Federal pipeline safety 
requirements do

[[Page 39921]]

not include overpressurization protection for farm taps. Therefore, 
this requirement would include inspection of farm-tap pressure 
regulating/limiting device, relief device, and automatic shutoff device 
every 3-years to make sure these safety equipment are in good working 
conditions.

VI. Reversal of Flow or Change in Product

Summary

    PHMSA published a final rule on November 26, 2010 (75 FR 72878) 
that established and required participation in the National Registry of 
Pipeline and LNG Operators. The final rule amended the Federal pipeline 
safety regulations to require operators to notify PHMSA electronically 
of the occurrence of certain events no later than 60 days before the 
event occurs.
    In this notice of proposed rulemaking (NPRM), PHMSA proposes 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 
proposed rule 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 proposed 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.

VII. Pipeline Assessment Tools

    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 notice 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.
    Section 195.452 specifies the techniques that must be used to 
perform the required periodic IM assessments.\2\ ILI is among the 
allowed techniques. Supervisory Control and Data Acquisition (SCADA) 
system 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.
---------------------------------------------------------------------------

    \2\ Operators are allowed to use techniques not specifically 
identified in these sections provided that the techniques provide an 
equivalent understanding of pipe condition and that operators notify 
PHMSA in advance of their use of such other techniques.
---------------------------------------------------------------------------

    When the IM regulations were established, consensus standards did 
not exist in addressing how these techniques should be applied. Since 
then, the American Petroleum Institute (API), National Association of 
Corrosion Engineers (NACE), and the American Society for Non-
Destructive Testing (ASNT) published standards for using ILI and SCCDA 
as assessment techniques. Also, PHMSA received a petition from NACE 
requesting that PHMSA incorporate ANSI/NACE Standard RP0204, NACE 
Standard RP0102-2002, and seven other NACE standards into 49 CFR parts 
192 and 195. These referenced consensus standards address the selection 
of in-line inspection tools for assessing the physical condition of in-
service hazardous liquids pipelines. Since the NACE petition, two of 
these standards have been developed from recommended practices into 
NACE Standard Practice (SP0102-2010 and NACE SP0204-2008.)
    In addition, NTSB issued the following safety recommendation to 
PHMSA on July 10, 2012, (P-12-3):

    Revise Title 49 Code of Federal Regulations 195.452 to clearly 
state (1) when an engineering assessment of crack defects, including 
environmentally assisted cracks, must be performed; (2) the 
acceptable methods for performing these engineering assessments, 
including the assessment of cracks coinciding with corrosion with a 
safety factor that considers the uncertainties associated with 
sizing of crack defects; (3) criteria for determining when a 
probable crack defect in a pipeline segment must be excavated and 
time limits for completing those excavations; (4) pressure 
restriction limits for crack defects that are not excavated by the 
required date; and (5) acceptable methods for determining crack 
growth for any cracks allowed to remain in the pipe, including 
growth caused by fatigue, corrosion fatigue, or stress corrosion 
cracking as applicable.

    This proposed rule would incorporate by reference consensus 
standards for assessing the physical condition of in-service hazardous 
liquids pipelines using ILI and SCCDA. Incorporation of the consensus 
standards would assure better consistency, accuracy and quality in 
pipeline assessments conducted using these techniques. This proposal 
addresses those parts of NTSB Recommendation P-12-3--identifying crack 
defects and seam corrosion by using crack tools and circumferential 
tools--by incorporating the above cited industry standards. The 
remainder of NTSB Recommendation P-12-3 will be addressed in PHMSA's 
rulemaking titled ``Pipeline Safety--Safety of On-Shore Hazardous 
Liquid Pipelines.'' Therefore, PHMSA proposes to incorporate by 
reference the following consensus standards 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). Also, PHMSA proposes to allow 
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.
    Note that this proposed rulemaking action addresses only part 195, 
but PHMSA is considering a similar proposed requirement in 49 CFR part 
192.

Justification for the Recommended Incorporation

    Incorporation of the consensus standards would 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 considers that the consistency, accuracy, and quality of 
pipeline ILI would be improved by

[[Page 39922]]

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 proposing to 
adopt 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, is proposing that use of these 
tools continue to be allowed 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 would provide further instructions when 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 would 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 would ensure that all operators use these 
standards. Overall cost would not change, because these consensus 
standards would 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 would 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.''
    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 would 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.
    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 would 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 (https://

[[Page 39923]]

primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=199). 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 this proposed 
rule (proposed Sec.  195.588) that an operator must consider if the 
operator uses direct assessment to assess SCC.
    SCC was also a topic in an advance notice of proposed rulemaking 
(ANPRM) published by PHMSA on October 18, 2010 (75 FR 63774). The ANPRM 
addressed several potential changes to the regulations governing the 
safety of hazardous liquids pipelines. Among other topics, it posed a 
number of questions concerning SCC, including whether the NACE standard 
addresses the full life cycle concerns associated with SCC, NACE's 
efficacy, and whether the NACE standard or any other standards should 
be adopted to govern the conduct of SCC assessments. PHMSA received a 
limited number of comments to the ANPRM that addressed the SCC 
questions. Joint comments from the American Petroleum Institute and the 
Association of Oil Pipelines (API-AOPL) noted that NACE SP0204-2008 is 
a reasonable standard but does not address all aspects of SCC control. 
API-AOPL noted that forthcoming updates of API Standard 1160, 
``Managing System Integrity for Hazardous Liquid Pipelines,'' and API 
Standard 1163, ``In-Line Inspection Systems Qualification Standard,'' 
would be better references to address SCC management. The Texas 
Pipeline Association recommended against adopting the NACE standard, 
contending that it is too new for operators to have significant 
experience with it. The National Association of Pipeline Safety 
Representatives suggested that PHMSA should require an assessment for 
SCC any time there is a credible threat of its occurrence; however, 
API-AOPL suggested that requiring assessment for ``any credible 
threat'' was too extreme and that some significance threshold should be 
used. The National Resources Defense Council suggested the need for 
special attention to sulfide-assisted SCC in pipelines carrying diluted 
bitumen (i.e., tar sands oil). No commenters indicated knowledge of 
statistics supporting the efficacy of any current SCC standard or 
guideline.
    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 
would adopt them.
    As for NAPSR's comment on assessing any credible SCC threat, PHMSA 
believes that any proposed requirements for SCC would need to be 
considered in a separate rulemaking effort. States always have option 
to make requirements more stringent. PHMSA will consider incorporating 
updates to API 1160 once that standard is published. PHMSA will also 
continue to consider the comments received in response to its ANPRM.
    PHMSA is proposing to revise 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 proposal would not require that SCCDA 
assessments be conducted, but it would 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.

VIII. Electronic Reporting of Drug and Alcohol Testing Results

    PHMSA's pipeline safety regulations at Sec. Sec.  191.7 and 195.58 
require electronic reporting of most pipeline safety reports through 
the PHMSA Portal. PHMSA proposes to also require electronic reporting 
for anti-drug testing results required at Sec.  199.119 and alcohol 
testing results required at Sec.  199.229. Pipeline operators with 
fewer than 50 covered employees are required to submit these reports 
only when PHMSA provides written notice. PHMSA proposes to modify these 
regulations to specify that PHMSA will provide notice to operators in 
the PHMSA Portal.

IX. Post-Accident Drug and Alcohol Testing

    The NTSB issued the following safety recommendation to PHMSA 
(September 26, 2011, NTSB Recommendation P-11-12):

    Amend Sec. Sec.  199.105 and 199.225 to eliminate operator 
discretion with regard to testing of covered employees. The revised 
language should require drug and alcohol testing of each employee 
whose performance either contributed to the accident or cannot be 
completely discounted as a contributing factor to the accident.

    PHMSA proposes to 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.
    PHMSA's regulations require 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 is only implied 
in the regulation, and the implied requirement is generally followed. 
PHMSA proposes to add a section to the post-accident drug testing 
regulation to require documentation of the decision and to keep the 
documentation for at least three years.

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

    When any 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 have a procedure in the pipeline safety regulations 
by which a request can be made for confidential treatment of 
information. PHMSA has such a procedure in its hazardous materials 
safety regulations. Therefore, for consistency in the way we treat 
submitted information, PHMSA proposes a procedure where anyone who 
submits information may request for confidential treatment of that 
information. As part of the procedure, if PHMSA receives a request for 
the record(s), PHMSA would conduct a

[[Page 39924]]

review of the records under the Freedom of Information Act.
    In accordance with Departmental FOIA regulations, if a request is 
received for information that has been designated by the submitter as 
confidential, we would notify the submitter and provide an opportunity 
to the submitter to submit any written objections. Whenever a decision 
is made to disclose such information over the objections of a 
submitter, we would notify the submitter in writing at least five days 
before the date the information is publicly disclosed.\3\
---------------------------------------------------------------------------

    \3\ Note--the Departmental FOIA regulations say that a written 
notice of intent to disclose will be forwarded a reasonable number 
of days prior to the specified date upon which disclosure is 
intended. See 49 CFR 7.17. See also the Hazmat regulations in 49 CFR 
105.30.
---------------------------------------------------------------------------

XI. In Service Welding

    In 1987, the U.S. Department of Transportation, Office of Pipeline 
Safety issued Alert Notice ALN-87-01 which advised pipeline owners and 
operators of a pipeline incident involving the welding of a full 
encirclement repair sleeve on a 14'' API 5L X52 pipeline near King of 
Prussia, PA. The pipeline failure released thousands of barrels of 
gasoline and was directly related to cracks developed in a fillet weld 
of a Type B full encirclement repair sleeve. The metallurgical analysis 
conducted by Battelle Laboratories concluded hydrogen and stress caused 
cracking of the excessively hard heat affected material in the carrier 
pipe. Contributing factors included poor weldability of the carrier 
pipe due to its high carbon equivalent, a very high cooling rate of the 
weld due to liquid product being present inside the pipeline during 
welding, the presence of hydrogen in the welding environment due to the 
use of cellulosic coated electrodes, residual stresses, and high 
restraint inherent in the geometry of the sleeve weldment. The alert 
notice strongly recommended that the use of welding procedures similar 
to the one that failed (use of cellulosic electrodes) be discontinued 
and that magnetic particle inspection has been proven to be an accurate 
method for detecting cracked in-service fillet welds.
    In response to this failure and advancements in pipeline and 
welding engineering, the American Petroleum Institute (API) developed, 
improved, and now includes Appendix B In-service Welding to the API 
Standard 1104 Welding of Pipelines and Related Facilities. API 1104 
Appendix B contains provisions for the development of welding 
procedures and welder qualifications that address the safety concerns 
of welding to an in-service pipeline. 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. 
At the present time, typical industry developed in-service welding 
procedures utilize all or some combinations of low hydrogen electrodes, 
preheat, temper bead deposition sequence, heat input control, cooling 
rate analysis, analysis based on pipe/sleeve/fitting material carbon 
equivalence, and address wall thickness/burn-through concerns. The 
Office of Pipeline Safety alert notice encouraged the development and 
use of welding procedures that address improvements in pipeline safety 
and many operators have developed in-service welding procedures.
    Unfortunately, parts 192 and 195 were not modified to include the 
addition of API 1104 Appendix B as an acceptable section for the 
development of welding procedures and welder qualification. At the 
present time, parts 192 and 195 only adopt into Federal Regulation 
Sections 5, 6, 9 and Appendix A. This proposed rule seeks to rectify 
this oversight and state the acceptability of developing procedures and 
qualifying welders to Appendix B of API 1104. Currently, PHMSA does not 
allow in service welding, but this proposal would allow the operators 
to follow Appendix B of API 1104 for in service welding. Therefore, 
PHMSA proposes to revise 49 CFR 192.225, 192.227, 195.214, and 195.222 
to add reference to API 1104, Appendix B.

XII. Editorial Amendments

    In this NPRM, PHMSA is also proposing to make the following 
editorial amendments to the pipeline safety regulations:

Summary of Correction to Sec.  192.175(b)

    PHMSA's predecessor agency, the Research and Special Programs 
Administration, issued a final rule on July 13, 1998; 63 FR 37500 to 
provide metric equivalents to the English units for informational 
purposes only. Operators were required to continue using the English 
units for purposes of compliance and enforcement. The metric equivalent 
provided in Sec.  192.175(b) ``C=(DxPxF/48.33) (C=(3DxPxF/1,000)''--is 
incorrect. The correct formula is: ``C = (3D*P*F)/1000) (C = (3D*P*F*)/
6,895)'', where, ``C = (3D*P*F)/1000)'' is in inches (English unit), 
and ``(C = (3D*P*F*)/6,895)'' is in millimeters (metric conversion).

Summary of Correction to Sec.  195.64(a) and Sec.  195.64(c)(1)(ii)

    PHMSA published a final rule on November 26, 2010; 75 FR 72878, 
which established the National Registry of Pipeline and LNG Operators. 
In the rule, PHMSA inadvertently omitted the inclusion of carbon 
dioxide in the operating commodity types. To maintain consistency with 
the rest of part 195, this proposed rule would amend the language in 
Sec. Sec.  195.64(a) and 195.64(c)(1)(ii) to correct the term 
``hazardous liquid'' to read ``hazardous liquid or carbon dioxide.''
    In Sec.  195.248, the conversion to 100 feet is mistakenly stated 
as 30 millimeters. Therefore, PHMSA proposes to replace the phrase 
``100 feet (30 millimeters)'' to correctly read ``100 feet (30.5 
meters).''
    In addition, low stress pipelines are not specified in Sec.  
195.452. Section 195.452 applies to each hazardous liquid pipeline and 
carbon dioxide pipeline that could affect a high consequence area, 
including any pipeline located in a high consequence area unless the 
operator effectively demonstrates by risk assessment that the pipeline 
could not affect the area. Therefore, PHMSA proposes to add a new 
paragraph (a)(4) to clarify the applicability of Sec.  195.452 to low 
stress pipelines as described in Sec.  195.12.

XIII. 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 (Pub. L. 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

[[Page 39925]]

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 requires the Secretary not to issue guidance or a regulation 
to incorporate 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.''
    Further, the Office of the Federal Register issued a November 7, 
2014, rulemaking (79 FR 66278) that revised 1 CFR 51.5 to require that 
agencies detail in the preamble of a proposed rulemaking the ways the 
materials it proposes to incorporate by reference are reasonably 
available to interested parties, or how the agency worked to make those 
materials reasonably available to interested parties. In relation to 
this proposed rulemaking, PHMSA has contacted each SDO and has 
requested free public access of each standard that has been proposed 
for incorporation by reference. Access to these standards will be 
granted until the end of the comment period for this proposed 
rulemaking. Access to these documents can be found on the PHMSA Web 
site at the following URL: https://www.phmsa.dot.gov/pipeline/regs under 
``Standards Incorporated by Reference.''

XIV. Regulatory Analyses and Notices

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

    This proposed rule is a non-significant regulatory action under 
Section 3(f) of Executive Order 12866 (58 FR 51735), and therefore is 
reviewed by the Office of Management and Budget. This proposed rule is 
non-significant under the Regulatory Policies and Procedures of the 
Department of Transportation (44 FR 11034) because of substantial 
congressional, State, industry, and public interest in pipeline safety.
    Executive Orders 12866 and 13563 require 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 notice, 
PHMSA is proposing 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;
     Modify operator qualification requirements including 
addressing a NTSB recommendation to clarify OQ requirements for control 
rooms;
     Add provisions for the renewal of expiring special 
permits;
     Exclude farm taps from the requirements of the DIMP 
requirements while proposing safety requirements for the farm taps
     To address NTSB recommendations for control room team 
training and other recommendations;
     Require pipeline operators to report to PHMSA 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;
     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;
     Add a procedure to ensure PHMSA keeps submitted 
information confidential.
     Adding reference to Appendix B of API 1104 related to in-
service welding in parts 192 and 195; and
     Making minor editorial corrections.
    As a summary of the costs/benefits the annual compliance costs were 
estimated at approximately $3.1 million, less savings to be realized 
from the removal of farm taps from the DIMP requirements. Annual safety 
benefits could not be quantified as readily due to data limitations but 
were estimated in the range of $1.6 million per year in avoided 
incident costs, plus numerous intangible benefits from the improved 
clarity and consistency of regulations and improved abilities to 
conduct post-incident investigations. Although the quantified benefits 
do not exceed the quantified costs, PHMSA believes that these non-
quantified benefits are significant enough to outweigh the costs of 
compliance. In particular, improvements to Operator Qualification and 
post-incident investigation may prevent a future high-consequence 
event. At an annual compliance cost of $3.1 million, the proposed new 
Operator Qualification and post-accident testing requirements would be 
cost-effective if they prevented a single fatal incident over a 3-year 
period.

                         Costs vs Benefits Table
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Annual Costs..............................  $3.1 million.
Annual Benefits...........................  $1.6 million plus
                                             unquantified safety
                                             benefits and farm tap
                                             savings.
------------------------------------------------------------------------

    A regulatory evaluation containing a statement of the purpose and 
need for this rulemaking and an analysis of the costs and benefits is 
available in Docket No. PHMSA-2013-0163.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether rulemaking actions would have a significant 
economic impact on a substantial number of small entities. PHMSA is 
proposing to add new requirements and make changes to the existing 
pipeline safety regulations.
    Description of the reasons why action by PHMSA is being considered.
    PHMSA is proposing to amend 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 proposed rule. A special permit renewal procedure is 
proposed so that pipeline operators would have a renewal procedure to 
follow to renew their expiring special permits. The OQ requirements 
scope is expanded for new constructions and a program effectiveness 
review is required so that Operators can review their OQ programs for 
effectiveness. In addition, other non-substantive changes are

[[Page 39926]]

proposed 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; process to request submitted information 
be kept confidential similar to the current Hazmat process in 49 CFR 
105.30; and, editorial amendments to correct some errors or outdated 
deadlines.
    Succinct statement of the objectives of, and legal basis for, the 
proposed 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)). The proposed rule would create changes in the regulations 
consistent with the protection of persons and property.
    Description of small entities to which the proposed rule will 
apply.
    The Initial Regulatory Flexibility Analysis finds that the proposed 
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 OQ provision would entail new costs for small entities 
in the range of $160.00 per employee per year, or about 0.3% of salary 
for a typical pipeline employee. The provision to document the reason 
for not drug testing post-accident would add $74.00 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 not expected to be 
significant.
    Description of any significant alternatives to the proposed rule 
that accomplish the stated objectives of applicable statutes and that 
minimize any significant economic impact of the proposed 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.

Questions for Comment on Regulatory Flexibility Analysis

    PHMSA is requesting public comments for the Regulatory Flexibility 
Analysis as follows:
    1. Provide any data concerning the number of small entities that 
may be affected.
    2. Provide comments on any or all of the provisions in the proposed 
rule with regard to (a) the impact of the provisions, if any, and (b) 
any alternatives PHMSA should consider, paying specific attention to 
the effect of the rule on small entities.
    3. Describe ways in which the rule could be modified to reduce any 
costs or burdens for small entities.
    4. Identify all relevant Federal, state, local, or industry rules 
or policies that may duplicate, overlap, or conflict with the proposed 
rule and have not already been incorporated by reference.

Executive Order 13175

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

Paperwork Reduction Act

    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 the proposals in this rulemaking 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 also proposes to create 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 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: July 31, 2015.
    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 proposing to revise the form PHMSA F7000-1 
instructions for editorial and clarification purposes. This proposal 
would result in a modification to the Hazardous Liquid Accident Report 
form (Form PHMSA F 7000-1) to include the concept of ``confirmed 
discovery'' as proposed in this rule.
    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.

[[Page 39927]]

    Current Expiration Date: October 31, 2017.
    Abstract: This proposal would result in a modification to the Gas 
Distribution Incident Report form (Form PHMSA F 7100.1) to include the 
concept of ``confirmed discovery'' as proposed in this rule.
    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: Qualification of Pipeline Safety Training''
    OMB Control Number: 2137-0600.
    Current Expiration Date: July 31, 2018.
    Abstract: All individuals responsible for the operation and 
maintenance of pipeline facilities are required to be properly 
qualified to safely perform their tasks and keep proper documentation 
as required by PHMSA regulations. As a result of the changes proposed 
in this NPRM, PHMSA estimates a total of 16,008 new employees will be 
subject to participate in an OQ plan either as a result of new 
gathering line requirements or because of newly covered tasks. 
Participation in an OQ plan necessitates the retention of records 
associated with those plans. This proposal will impose a recordkeeping 
requirement for Operator Qualifications on the estimated 16,008 newly 
covered employees that will be affected by this rule. As a result, 
16,008 responses and 42,668 annual burden hours will be added to the 
existing information collection burden.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 31,835
    Total Annual Burden Hours: 509,360.
    Frequency of Collection: On occasion.
    4. 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 proposed rule would amend 
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 proposed 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.
    5. 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 NPRM proposes to amend 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 609 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.
    Comments are invited on:
    (a) The need for the proposed collection of information for the 
proper performance of the functions of the agency, including whether 
the information will have practical utility;
    (b) The accuracy of the agency's estimate of the burden of the 
revised collection of information, including the validity of the 
methodology and assumptions used;
    (c) Ways to enhance the quality, utility, and clarity of the 
information to be collected; and
    (d) Ways to minimize the burden of the collection of information on 
those who are to respond, including the use of appropriate automated, 
electronic, mechanical, or other technological collection techniques.
    Send comments directly to the Office of Management and Budget, 
Office of Information and Regulatory Affairs, Attn: Desk Officer for 
the Department of Transportation, 725 17th Street NW., Washington, DC 
20503. Comments should be submitted on or prior to September 8, 2015.

Unfunded Mandates Reform Act of 1995

    PHMSA has determined that the proposed rule would not impose annual 
expenditures on State, local, or tribal governments of the private 
sector in excess of $153 million, and thus, does not require an 
Unfunded Mandates Act analysis.\4\
---------------------------------------------------------------------------

    \4\ The Unfunded Mandates Act threshold was $100 million in 
1995. Using the non-seasonally adjusted CPI-U (Index series 
CUUR000SA0), that number is $153 million in 2013 dollars.
---------------------------------------------------------------------------

National Environmental Policy Act

    The National Environmental Policy Act (42 U.S.C. 4321 through 4375) 
requires that Federal agencies analyze proposed actions to determine 
whether those actions will have a significant impact on the human 
environment. The Council on Environmental Quality regulations require 
Federal agencies to conduct an environmental review considering: (1) 
The need for the proposed action, (2) alternatives to the proposed 
action, (3) probable environmental impacts of the proposed action and 
alternatives, and (4) the agencies and persons consulted during the 
consideration process (40 CFR 1508.9(b)).
1. Purpose and Need
    PHMSA's mission is to protect people and the environment from the 
risks of hazardous materials transportation. The purpose of this 
proposed rule 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.

[[Page 39928]]

    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 
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 the proposed rule, PHMSA considered two alternatives:
    (1) No action, or
    (2) Propose revisions to the pipeline safety regulations to 
incorporate the proposed 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 
proposed in this proposed rule 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 proposing to make 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. We are also proposing 
changes to the OQ requirements and drug and alcohol testing 
requirements and proposing methods for assessment tools by 
incorporating consensus standards by reference for in-line inspection 
and stress corrosion cracking direct assessment.
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 the proposed 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 the proposed 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 proposed 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 preliminarily determined that the selected alternative 
would have a positive, non-significant, impact on the human environment 
and welcomes comments on PHMSA's conclusion. The preliminary 
environmental assessment is available in Docket No. PHMSA-2013-0163.

Executive Order 13132

    PHMSA has analyzed this proposed rule according to Executive Order 
13132 (``Federalism''). The proposed 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 proposed 
rule does not impose substantial direct compliance costs on State and 
local governments. This proposed 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 proposed rule is not a ``significant energy action'' under 
Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use''). It is not 
likely to have a significant adverse effect on supply, distribution, or 
energy use. Further, the Office of Information and Regulatory Affairs 
has not designated this proposed rule as a significant energy action.

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 Part192

    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,

[[Page 39929]]

Incorporation by reference, Operator qualification, Petroleum, Pipeline 
safety, Reporting and recordkeeping requirements, Reversal of flow, 
Safety devices.

49 CFR Part 199

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

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

PART 190--PIPELINE SAFETY ENFORCEMENT AND REGULATORY PROCEDURES

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

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

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.
* * * * *
0
3. Amend Sec.  190.341 by:
0
a. Revising paragraph (c)(8) and removing, paragraph (c)(9);
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) * * *
    (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 https://www.phmsa.dot.gov/.
    (e) How does PHMSA handle special permit renewals? (1) To continue 
using a special permit after the expiration date, the grantee of the 
special permit must apply for a renewal of the permit.
    (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., East Building, 
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:
    (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:
    (A) Pipe attributes: Pipe diameter, wall thickness, grade, and seam 
type; 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;
    (F) In-line inspection (ILI): ILI survey results from all ILI tools 
used on the special permit segments during the previous five years;
    (G) Integrity Data and Integration: The following information, as 
applicable, for the past five (5) years: Hydrostatic test pressure 
including any known test failures; casings(any shorts); any in-service 
ruptures or leaks; close interval survey (CIS) surveys; depth of cover 
surveys; rectifier readings; test point survey readings; AC/DC 
interference surveys; pipe coating surveys; pipe coating and anomaly 
evaluations from pipe excavations; SCC, selective seam corrosion 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 to read as follows:


Sec.  190.343.  Information made available to the public and request 
for confidential treatment.

    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.
    (a) Asking for confidential treatment. 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 information deleted.

[[Page 39930]]

    (3) Explain why the information you are submitting is confidential.
    (b) PHMSA Decision. PHMSA will decide whether to treat your 
information as confidential. We will notify you, in writing, of a 
decision to grant or deny confidentiality at least five days before the 
information is publicly disclosed, and give you an opportunity to 
respond
0
5. In part 190, subpart E is added to read asfollows:

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: 
Construction route surveys, permitting activities, material purchasing 
and manufacturing, right of way acquisition, 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]


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

[[Page 39931]]

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, as revised in 80 FR12762 (March 
11, 2015), effective October 1, 2015, continues to read as follows:

    Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 
60118, and 60124, 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 there is sufficient information to 
determine that a reportable event may have occurred even if an 
evaluation has not been completed.
* * * * *
0
8. In Sec.  191.5, paragraph (a) is revised, paragraph (b)(5) is re-
designated as paragraph (b)(6) and new paragraph (b)(5) and paragraph 
(c) are 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.
    (b) * * *
    (5) The amount of product loss.
* * * * *
    (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 a revised 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)(iv) and (c)(1)(v) 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;
* * * * *
    (iv) 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
    (v) 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, as revised in 80 FR 12762 
(March 11, 2015), effective October 1, 2015, continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, 60118, and 60137; and 49 CFR 1.97.

0
11. In Sec.  192.9, paragraph (c) is revised, paragraph (d)(8) is 
added, and the table in paragraph (e)(2) is revised to read as follows:


Sec.  192.9  What requirements apply to gathering lines?

* * * * *
    (c) Type A lines. An operator of a Type A regulated onshore 
gathering line must comply with the requirements of this part 
applicable to transmission lines, except the requirements in Sec.  
192.150 and in subpart O of this part. An operator must establish and 
implement an operator qualification program in accordance with Subpart 
N of this part.
    (d) * * *
    (8) Establish and implement an operator qualification program in 
accordance with Subpart N of this part.
* * * * *
    (e) * * *
    (2) If a regulated onshore gathering line existing on April 14, 
2006 was not previously subject to this part, an operator has until the 
date stated in the second column to comply with the applicable 
requirement for the line listed in the first column, unless the 
Administrator finds a later deadline is justified in a particular case:

------------------------------------------------------------------------
                Requirement                      Compliance deadline
------------------------------------------------------------------------
Control corrosion according to Subpart I    April 15, 2009.
 requirements for transmission lines.
Carry out a damage prevention program       October 15, 2007.
 under Sec.   192.614.
Establish MAOP under Sec.   192.619.......  October 15, 2007.
Install and maintain line markers under     April 15, 2008.
 Sec.   192.707.
Establish a public education program under  April 15, 2008.
 Sec.   192.616.
Establish an operator qualification         [date one year after
 program according to Subpart N              publication of a final
 requirements if an operator of a Type A     rule].
 or Type B regulated onshore gathering
 line.
Other provisions of this part as required   April 15, 2009.
 by paragraph (c) of this section for Type
 A lines.
------------------------------------------------------------------------

* * * * *
0
12. 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
13. 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.


[[Page 39932]]


0
14. 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
15. 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
16. In Sec.  192.631, paragraphs (b)(3), (b)(4), (h)(4) and (h)(5) are 
revised and paragraphs (b)(5) and (h)(6) are added to read as follows:


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 who would reasonably be expected to 
interact with controllers (control room personnel) during normal, 
abnormal or emergency situations.
* * * * *
0
17. Section 192.740 is added to read as follows:


Sec.  192.740  Pressure regulating, limiting, and overpressure 
protection--Individual service lines originating on production, 
gathering, or transmission pipelines.

    (a) This section applies, except as provided in paragraph (c) of 
this section, to any service line that originates from a production, 
gathering, or transmission pipeline that is not operated as part of a 
distribution system.
    (b) Each pressure regulating/limiting device, relief device, 
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) gage 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
18. Section 192.801 is revised to read as follows:


Sec.  192.801  Scope.

    This subpart prescribes the minimum requirements for operator 
qualification of individuals performing covered tasks as defined in 
Sec.  192.803 on a pipeline facility.
0
19. Section 192.803 is revised to read as follows:


Sec.  192.803  Definitions.

    For purposes of the subpart the following definitions apply:
    Abnormal operating condition means a condition identified by the 
operator that may indicate a malfunction of a component or deviation 
from normal operations that may:
    (1) Indicate a condition exceeding design limits; or
    (2) Result in a hazard(s) to persons, property, or the environment.
    Adversely affects means a negative impact on the safety or 
integrity of the pipeline facilities.
    Covered task means an activity identified by the operator that 
affects the safety or integrity of the pipeline facility. A covered 
task includes, but is not limited to, the performance of any 
operations, maintenance, construction or emergency response task.
    Direct and observe means the process where a qualified individual 
personally observes the work activities of an individual not qualified 
to perform a single covered task, and is able to take immediate 
corrective action when necessary.
    Emergency response tasks are those identified operations and 
maintenance covered tasks that could reasonably be expected to be 
performed during an emergency to return the pipeline facilities to a 
safe operating condition.
    Evaluation means a process, established and documented by the 
operator, to determine an individual's ability to perform a covered 
task by any of the following:
    (1) Written examination;
    (2) Oral examination;
    (3) Work performance history review;
    (4) Observation during;
    (i) Performance on the job;
    (ii) On the job training; or
    (iii) Simulations; and
    (5) Other forms of assessment
    Knowledge, skills and abilities, as it applies to individuals 
performing a covered task, means that an individual can apply 
information to the performance of a covered task, has the ability to 
perform mental and physical activities developed or acquired through 
training, and has the mental and physical capacity to perform the 
covered task.
    Qualified as it applies to an individual performing a covered task, 
means that an individual has been evaluated and can:
    (1) Perform assigned covered tasks;
    (2) Recognize and react to abnormal operating conditions that may 
be encountered while performing a particular covered task;
    (3) Demonstrate technical knowledge required to perform the covered 
task, such as: equipment selection, maintenance of equipment, 
calibration and proper operation of equipment, including variations 
that may be encountered in the covered task performance due to 
equipment and environmental differences;

[[Page 39933]]

    (4) Demonstrate the technical skills required to perform the 
covered task, for example:
    (i) Variations required in the covered task performance due to 
equipment and/or new operations differences or changes;
    (ii) Variations required in covered task performance due to 
conditions or context differences (e.g., hot work versus work on 
evacuated pipeline); and
    (5) Meet the physical abilities required to perform the specific 
covered task (e.g., color vision or hearing).
    Safety or integrity means the reliable condition of a pipeline 
facility (operationally sound or having the ability to withstand 
stresses imposed) affected by any operation, maintenance or 
construction task, and/or an emergency response.
    Significant changes means the following as it relates to operator 
qualification:
    (1) Wholesale changes to the program;
    (2) Change in evaluation methods (i.e. performance and written to 
written only);
    (3) Increases in evaluation intervals (i.e. from 1 to 5 years); or
    (4) Removal of covered tasks (not including combining covered 
tasks).
    Span of control means the ratio of nonqualified to qualified 
individuals where the nonqualified individual may be directed and 
observed by a qualified individual when performing a covered task, with 
consideration to complexity of the covered task and the operational 
conditions when performing the covered task.
0
20. Section 192.805 is revised to read as follows:


Sec.  192.805  Qualification program.

    (a) General. An operator must have and follow a written operator 
qualification program that meets the requirements of paragraph (b) of 
this section for all pipelines regulated under part 192. The written 
program must be available for review by the Administrator or by a state 
agency participating under 49 U.S.C. chapter 601 if the program is 
under the authority of that state agency.
    (b) Program Requirements. The operator qualification program must, 
at a minimum, include provisions to:
    (1) Identify covered tasks;
    (2) Complete the qualification of each individual performing a 
covered task prior to the individual performing the covered task;
    (3) Ensure through evaluation that each individual performing a 
covered task is qualified to perform the covered task provided that:
    (i) Review of work performance history is not used as a sole 
evaluation method.
    (ii) Observation of on-the-job performance is not used as a sole 
method of evaluation. However, when on-the-job performance is used to 
complete an individual's competency for a covered task, the operator 
qualification procedure must define the measures used to determine 
successful completion of the on-the-job performance evaluation.
    (4) Allow any individual who is not qualified to perform a covered 
task to perform the covered task if directed and observed by a 
qualified individual within the limitations of the established span of 
control for the particular covered task.
    (5) Evaluate an individual if the operator has reason to believe 
that the individual's performance of a covered task contributed to an 
incident as defined in part 191 of this chapter;
    (6) Evaluate an individual if the operator has reason to believe 
that the individual is no longer qualified to perform a covered task;
    (7) Establish and maintain a Management of Change program that will 
communicate changes that affect covered tasks to individuals performing 
those covered tasks;
    (8) Identify all covered tasks and the intervals at which 
evaluation of an individual's qualifications is needed;
    (9) Provide training to ensure that any individual performing a 
covered task has the necessary knowledge, skills, and abilities to 
perform the task in a manner that ensures the safety and integrity of 
the operator's pipeline facilities;
    (10) Provide supplemental training for the individual when 
procedures and specifications are changed for the covered task;
    (11) Establish the requirements to be an Evaluator, including the 
necessary training; and
    (12) Develop and implement a process to measure the program's 
effectiveness in accordance with Sec.  192.805
    (c) Changes. An operator must notify the Administrator or a State 
agency participating under 49 U.S.C. Chapter 601 if the operator 
significantly modifies the program after the Administrator or state 
agency has verified that it complies with this section. Notifications 
to PHMSA may be submitted by electronic mail to 
InformationResourcesManager@dot.gov, or by mail to ATTN: Information 
Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New 
Jersey Avenue SE., Washington, DC 20590.
0
21. Section 192.807 is revised to read as follows:


Sec.  192.807  Program effectiveness.

    (a) General. The qualification program must include a written 
process to measure the program's effectiveness. An effective program 
minimizes human error caused by an individual's lack of knowledge, 
skills and abilities (KSAs) to perform covered tasks. An operator must 
conduct the program effectiveness review once each calendar year not to 
exceed 15 months.
    (b) Process. The process to measure program effectiveness must:
    (1) Evaluate if the qualification program is being implemented and 
executed as written; and
    (2) Establish provisions to amend the program to include any 
changes necessary to address the findings of the program effectiveness 
review.
    (c) Measures. The operator must develop program measures to 
determine the effectiveness of the qualification program. The operator 
must, at a minimum, include and use the following measures to evaluate 
the effectiveness of the program.
    (1) Number of occurrences caused by any individual whose 
performance of a covered task(s) adversely affected the safety or 
integrity of the pipeline due to any of the following deficiencies:
    (i) Evaluation was not conducted properly;
    (ii) KSAs for the specific covered task(s) were not adequately 
determined;
    (iii) Training was not adequate for the specific covered task(s);
    (iv) Change made to a covered task or the KSAs was not adequately 
evaluated for necessary changes to training or evaluation;
    (v) Change to a covered task(s) or the KSAs was not adequately 
communicated;
    (vi) Individual failed to recognize an abnormal operating 
condition, whether it is task specific or non-task specific, which 
occurs anywhere on the system;
    (vii) Individual failed to take the appropriate action following 
the recognition of an abnormal operating condition (task specific or 
non-task specific) that occurs anywhere on the system;
    (viii) Individual was not qualified;
    (ix) Nonqualified individual was not being directed and observed by 
a qualified individual;
    (x) Individual did not follow approved procedures and/or use 
approved equipment;
    (xi) Span of control was not followed;
    (xii) Evaluator or training did not follow program or meet 
requirements; or

[[Page 39934]]

    (xiii) The qualified individual supervised more than one covered 
task at the time.
    (2) [Reserved]
0
22. Section 192.809 is revised to read as follows:


Sec.  192.809  Recordkeeping.

    Each operator must maintain records that demonstrate compliance 
with this subpart.
    (a) Individual qualification records. Individual qualification 
records must include:
    (1) Identification of qualified individual(s),
    (2) Identification of the covered tasks the individual is qualified 
to perform;
    (3) Date(s) of current qualification;
    (4) Qualification method(s);
    (5) Evaluation to recognize and react to an abnormal operating 
condition, whether it is task-specific non-task specific, which occurs 
anywhere on the system;
    (6) Name of evaluator and date of evaluation; and
    (7) Training required to support an individual's qualification or 
requalification.
    (b) Program records. Program records must include, at a minimum, 
the following:
    (1) Program effectiveness reviews;
    (2) Program changes;
    (3) List of program abnormal operating conditions;
    (4) Program management of change notifications;
    (5) Covered task list to include all task specific and non-task 
specific covered tasks;
    (6) Span of control ratios for each covered task:
    (7) Reevaluation intervals for each covered task;
    (8) Evaluations method(s) for each covered task; and
    (9) Criteria and training for evaluators.
    (c) Retention period--(1) Individual qualification records. An 
operator must maintain records of qualified individuals who performed 
covered tasks. Records supporting an individual's current qualification 
must be retained while the individual is performing the covered task. 
Records of prior qualification and records of individuals no longer 
performing covered tasks must be retained for a period of five years.
    (2) Program records. An operator must maintain records required by 
paragraph (b) of this section for a period of five years.
0
23. Section 192.1003 is revised to read as follows:


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

    (a) General. Unless excepted 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 a service line that 
originates directly from a transmission, gathering, or production 
pipeline.

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
24. The authority citation for part 195, as revised in 80 FR12762 
(March 11, 2015), effective October 1, 2015, continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118, 
60137, and 49 CFR 1.97.
0
25. 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 there is sufficient information to 
determine that a reportable event may have occurred even if an 
evaluation has not been completed.
* * * * *
    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
26. In Sec.  195.3:
0
a. Add paragraph (b)(23);
0
b. Redesignate paragraphs (d) through (h) as (e) through (i) 
respectively and add a new paragraph (d); and
0
c. Add paragraphs (g)(3) and (4) to the newly redesignated paragraph 
(g).
    The additions read as follows:


Sec.  195.3  Incorporation by reference.

* * * * *
    (b) * * *
    (23) API Standard 1163, ``In-Line Inspection Systems Qualification 
Standard'' 1st edition, August 2005, (API Std 1163), IBR approved for 
Sec.  195.591.
* * * * *
    (d) American Society for Nondestructive Testing, P.O. Box 28518, 
1711 Arlingate Lane, Columbus, OH, 43228. https://asnt.org.
    (1) ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel 
Qualification and Certification'' (2010), (ANSI/ASNT ILI-PQ), IBR 
approved for Sec.  195.591.
    (2) [Reserved]
* * * * *
    (g) * * *
    (3) NACE SP0102-2010, Standard Practice, ``Inline Inspection of 
Pipelines'' approved March 3, 2010, (NACE SP0102), IBR approved for 
Sec.  195.591
    (4) NACE SP0204-2008, Standard Practice, ``Stress Corrosion 
Cracking Direct Assessment'' approved September 18, 2008, (NACE 
SP0204), IBR approved for Sec.  195.588(c).
0
27. 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
28. In Sec.  195.11 paragraph (b)(11) is revised to read as follows:


Sec.  195.11  What is a regulated rural gathering line and what 
requirements apply?

* * * * *
    (b) * * *
    (11) Establish and implement an operator qualification program in 
accordance with Subpart G of this part before [DATE ONE YEAR AFTER DATE 
OF PUBLICATION OF A FINAL RULE IN THE FEDERAL REGISTER].
* * * * *

[[Page 39935]]

0
29. 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
30. 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
31. In Sec.  195.64, as amended at 80 FR 12762 (March 11, 2015), 
effective October 1, 2015, paragraph (c)(1)(ii) is revised and 
paragraphs (c)(1)(iii) and (c)(1)(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
32. In Sec.  195.120, the title 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
33. In Sec.  195.214, as amended at 80 FR 12762 (March 11, 2015), 
effective October 1, 2015, 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
34. In Sec.  195.222, as amended at 80 FR 12762 (March 11, 2015), 
effective October 1, 2015, 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
35. In Sec.  195.248, the phrase ``100 feet (30 millimeters)'' is 
removed and replaced with the phrase ``100 feet (30.5 meters)'' in the 
table to paragraph (a).
0
36. In Sec.  195.446, revise paragraphs (b)(3) and (b)(4), add 
paragraph (b)(5), revise paragraphs (h)(4) and (h)(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 that includes both controllers and 
other individuals who would reasonably be expected to interact with 
controllers (control room personnel) during normal, abnormal or 
emergency situations.
* * * * *
0
37. In Sec.  Section 195.452, paragraph (a)(4) is added, 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, cracks, and deformation anomalies including dents, gouges 
and grooves. 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, cracks, and deformation anomalies including dents, gouges 
and grooves. When performing an assessment using an In-Line Inspection 
tool, an operator must comply with Sec.  195.591;
* * * * *
0
38. Section 195.501 is revised to read as follows:

[[Page 39936]]

Sec.  195.501  Scope.

    This subpart prescribes the minimum requirements for operator 
qualification of individuals performing covered tasks as defined in 
Sec.  195.503 on a pipeline facility.
0
39. Section 195.503 is revised to read as follows:


Sec.  195.503  Definitions.

    For purposes of this subpart the following definitions apply:
    Abnormal operating condition means a condition identified by the 
operator that may indicate a malfunction of a component or deviation 
from normal operations that may:
    (1) Indicate a condition exceeding design limits; or
    (2) Result in a hazard(s) to persons, property, or the environment.
    Adversely affects means a negative impact on the safety or 
integrity of the pipeline facilities.
    Covered task means an activity identified by the operator that 
affects the safety or integrity of the pipeline facility. A covered 
task includes, but is not limited to, the performance of any 
operations, maintenance, construction or emergency response task
    Direct and observe means the process where a qualified individual 
personally observes the work activities of an individual not qualified 
to perform a single covered task, and is able to take immediate 
corrective action when necessary.
    Emergency response tasks are those identified operations and 
maintenance covered tasks that could reasonably be expected to be 
performed during an emergency to return the pipeline facilities to a 
safe operating condition.
    Evaluation means a process, established and documented by the 
operator, to determine an individual's ability to perform a covered 
task by any of the following:
    (1) Written examination;
    (2) Oral examination;
    (3) Work performance history review;
    (4) Observation during;
    (i) Performance on the job;
    (ii) On the job training; or
    (iii) Simulations; and
    (5) Other forms of assessment
    Knowledge, skills and abilities, as it applies to individuals 
performing a covered task, means that an individual can apply 
information to the performance of a covered task, has the ability to 
perform mental and physical activities developed or acquired through 
training, and has the mental and physical capacity to perform the 
covered task.
    Qualified as it applies to an individual performing a covered task, 
means that an individual has been evaluated and can:
    (1) Perform assigned covered tasks;
    (2) Recognize and react to abnormal operating conditions that may 
be encountered while performing a particular covered task;
    (3) Demonstrate technical knowledge required to perform the covered 
task, such as: Equipment selection, maintenance of equipment, 
calibration and proper operation of equipment, including variations 
that may be encountered in the covered task performance due to 
equipment and environmental differences;
    (4) Demonstrate the technical skills required to perform the 
covered task, for example:
    (i) Variations required in the covered task performance due to 
equipment and/or new operations differences or changes;
    (ii) Variations required in covered task performance due to 
conditions or context differences (e.g., hot work versus work on 
evacuated pipeline); and
    (5) Meet the physical abilities required to perform the specific 
covered task (e.g., color vision or hearing).
    Safety or integrity means the reliable condition of a pipeline 
facility (operationally sound or having the ability to withstand 
stresses imposed) affected by any operation, maintenance or 
construction task, and/or an emergency response.
    Significant changes means the following as it relates to operator 
qualification:
    (1) Wholesale changes to the program;
    (2) Change in evaluation methods (i.e. performance and written to 
written only);
    (3) Increases in evaluation intervals (i.e. from 1 to 5 years); or
    (4) Removal of covered tasks (not including combining covered 
tasks).
    Span of control means the ratio of nonqualified to qualified 
individuals where the nonqualified individual may be directed and 
observed by a qualified individual when performing a covered task, with 
consideration to complexity of the covered task and the operational 
conditions when performing the covered task.
0
40. Section 195.505, as amended at 80 FR 12762 (March 11, 2015), 
effective October 1, 2015, is revised to read as follows:


Sec.  195.505  Qualification program.

    (a) General. An operator must have and follow a written operator 
qualification program that meets the requirements of paragraph (b) of 
this section for all pipelines regulated under part 195. The written 
program must be available for review by the Administrator or by a state 
agency participating under 49 U.S.C. Chapter 601 if the program is 
under the authority of that state agency.
    (b) Program requirements. The operator qualification program must, 
at a minimum, include provisions to:
    (1) Identify covered tasks;
    (2) Complete the qualification of each individual performing a 
covered task prior to the individual performing the covered task;
    (3)(i) Ensure through evaluation that each individual performing a 
covered task is qualified to perform the covered task provided that:
    (A) Review of work performance history is not used as a sole 
evaluation method.
    (B) Observation of on-the-job performance is not used as a sole 
method of evaluation. (ii) However, when on-the-job performance is used 
to complete an individual's competency for covered tasks, the operator 
qualification procedure must define the measures used to determine 
successful completion of the on-the-job performance evaluation.
    (4) Allow any individual who is not qualified pursuant to this 
subpart to perform a covered task if directed and observed by a 
qualified individual within the limitations of the established span of 
control for the particular covered task;
    (5) Evaluate an individual if the operator has reason to believe 
that the individual's performance of a covered task contributed to an 
accident as defined in Sec.  195.52;
    (6) Evaluate an individual if the operator has reason to believe 
that the individual is no longer qualified to perform a covered task;
    (7) Establish and maintain a Management of Change program that will 
communicate changes that affect covered tasks to individuals performing 
those covered tasks;
    (8) Identify all covered tasks and the intervals at which 
evaluation of an individual's qualifications is needed;
    (9) Provide training to ensure that any individual performing a 
covered task has the necessary knowledge, skills, and abilities to 
perform the task in a manner that ensures the safety and integrity of 
the operator's pipeline facilities;
    (10) Provide supplemental training for the individual when 
procedures and specifications are changed for the covered task;
    (11) Establish the requirements to be an Evaluator, including the 
necessary training; and

[[Page 39937]]

    (12) Develop and implement a process to measure the program's 
effectiveness in accordance with Sec.  195.505
    (c) Changes. An operator must notify the Administrator or a State 
agency participating under 49 U.S.C. Chapter 601 if the operator 
significantly modifies the program after the Administrator or state 
agency has verified that it complies with this section. Notifications 
to PHMSA may be submitted by electronic mail to 
InformationResourcesManager@dot.gov, or by mail to ATTN: Information 
Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New 
Jersey Avenue SE., Washington, DC 20590.
0
41. Section 195.507 is revised to read as follows:


Sec.  195.507  Program effectiveness.

    (a) General. The qualification program must include a written 
process to measure the program's effectiveness. An effective program 
minimizes human error caused by an individual's lack of knowledge, 
skills and abilities (KSAs) to perform covered tasks. An operator must 
conduct the program effectiveness review once each calendar year not to 
exceed 15 months.
    (b) Process. The process to measure program effectiveness must:
    (1) Evaluate if the qualification program is being implemented and 
executed as written; and
    (2) Establish provisions to amend the program to include any 
changes necessary to address the findings of the program effectiveness 
review.
    (c) Measures. The operator must develop program measures to 
determine the effectiveness of the qualification program. The operator 
must, at a minimum, include and use the following measures to evaluate 
the effectiveness of the program.
    (1) Number of occurrences caused by any individual whose 
performance of a covered task(s) adversely affected the safety or 
integrity of the pipeline due to any of the following deficiencies:
    (i) Evaluation was not conducted properly;
    (ii) KSAs for the specific covered task(s) were not adequately 
determined;
    (iii) Training was not adequate for the specific covered task(s);
    (iv) Change made to a covered task or the KSAs was not adequately 
evaluated for necessary changes to training or evaluation;
    (v) Change to a covered task(s) or the KSAs was not adequately 
communicated;
    (vi) Individual failed to recognize an abnormal operating 
condition, whether it is task-specific or non-task specific, which 
occurs anywhere on the system;
    (vii) Individual failed to take the appropriate action following 
the recognition of an abnormal operating condition (task-specific or 
non-task-specific) that occurs anywhere on the system;
    (viii) Individual was not qualified;
    (ix) Nonqualified individual was not being directed and observed by 
a qualified individual;
    (x) Individual did not follow approved procedures and/or use 
approved equipment;
    (xi) Span of control was not followed;
    (xii) Evaluator or training did not follow program or meet 
requirements; or
    (xiii) The qualified individual supervised more than one covered 
task at the time.
    (2) [Reserved]
0
42. Section 195.509 is revised to read as follows:


Sec.  195.509  Recordkeeping.

    Each operator must maintain records that demonstrate compliance 
with this subpart.
    (a) Individual qualification records. Individual qualification 
records must include at a minimum:
    (1) Identification of qualified individual(s),
    (2) Identification of the covered tasks the individual is qualified 
to perform;
    (3) Date(s) of current qualification;
    (4) Qualification method(s);
    (5) Evaluation to recognize and react to an abnormal operating 
condition, whether it is task-specific or non-task-specific, which 
occurs anywhere on the system;
    (6) Name of evaluator and date of evaluation; and
    (7) Training required to support an individual's qualification or 
requalification.
    (b) Program records. Program records must include, at a minimum, 
the following:
    (1) Program effectiveness reviews;
    (2) Program changes;
    (3) List of program abnormal operating conditions;
    (4) Program management of change notifications;
    (5) Covered task list to include all task-specific and non-task 
specific covered tasks;
    (6) Span of control ratios for each covered task:
    (7) Reevaluation intervals for each covered task;
    (8) Evaluations method(s) for each covered task; and
    (9) Criteria and training for evaluators.
    (c) Retention period--(i) Individual qualification records. An 
operator must maintain records of qualified individuals who performed 
covered tasks. Records supporting an individual's current qualification 
must be retained while the individual is performing the covered task. 
Records of prior qualification and records of individuals no longer 
performing covered tasks must be retained for a period of five years.
    (ii) Program records. An operator must maintain records as required 
in paragraph (b) of this section for a period of five years.
0
43. 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

[[Page 39938]]

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 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 of the pipe 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;
    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and
    (ix) Disbonded coatings that shield CP from the pipe.
0
44. 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 1163-2005, Inline Inspection Systems 
Qualification Standard; ANSI/ASNT ILI-PQ-2010, 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
45. The authority citation for part 199 is revised to read as follows:

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

0
47. 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 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.
    (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
47. 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
48. In Sec.  199.119, paragraphs (a) and (b) are revised to read as 
follows:

[[Page 39939]]

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 https://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
49. 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
50. 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
51. 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 https://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.
* * * * *

    Issued in Washington, DC, on June 26, 2015, under authority 
delegated in 49 CFR part 1.97.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2015-16264 Filed 7-9-15; 8:45 am]
 BILLING CODE 4910-60-P