Document ID: PHMSA-2010-0229-0135
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Safety of Hazardous Liquid Pipelines
Posted Date: 2019-10-01T04:00Z

[Federal Register Volume 84, Number 190 (Tuesday, October 1, 2019)]
[Rules and Regulations]
[Pages 52260-52298]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-20458]

[[Page 52259]]

Vol. 84

Tuesday,

No. 190

October 1, 2019

Part III

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Part 195

Pipeline Safety: Safety of Hazardous Liquid Pipelines; Final Rule

  Federal Register / Vol. 84 , No. 190 / Tuesday, October 1, 2019 / 
Rules and Regulations  

[[Page 52260]]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 195

[Docket No. PHMSA-2010-0229; Amdt. No. 195-102]
RIN 2137-AE66

Pipeline Safety: Safety of Hazardous Liquid Pipelines

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

ACTION: Final rule.

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SUMMARY: In response to congressional mandates, NTSB and GAO 
recommendations, lessons learned, and public input, PHMSA is amending 
the Pipeline Safety Regulations to improve the safety of pipelines 
transporting hazardous liquids. Specifically, PHMSA is extending 
reporting requirements to certain hazardous liquid gravity and rural 
gathering lines; requiring the inspection of pipelines in areas 
affected by extreme weather and natural disasters; requiring integrity 
assessments at least once every 10 years of onshore hazardous liquid 
pipeline segments located outside of high consequence areas and that 
are ``piggable'' (i.e., can accommodate in-line inspection devices); 
extending the required use of leak detection systems beyond high 
consequence areas to all regulated, non-gathering hazardous liquid 
pipelines; and requiring that all pipelines in or affecting high 
consequence areas be capable of accommodating in-line inspection tools 
within 20 years, unless the basic construction of a pipeline cannot be 
modified to permit that accommodation. Additionally, PHMSA is 
clarifying other regulations and is incorporating Sections 14 and 25 of 
the PIPES Act of 2016 to improve regulatory certainty and compliance.

DATES: The effective date of this final rule is July 1, 2020. The 
incorporation by reference of certain publications listed in the rule 
was approved by the Director of the Federal Register as of March 24, 
2017 and March 6, 2015.

FOR FURTHER INFORMATION CONTACT:
    Technical questions: Steve Nanney, Project Manager, by telephone at 
713-272-2855.
    General information: Robert Jagger, Senior Transportation 
Specialist, by telephone at 202-366-4361.

SUPPLEMENTARY INFORMATION: 

I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Regulatory Action in 
Question
    C. Costs and Benefits
II. Background
    A. Detailed Overview
    B. Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011
    C. National Transportation Safety Board Recommendations
    D. Summary of Each Topic
III. Pipeline Advisory Committee
IV. Analysis of Comments and PHMSA Response
    A. Reporting Requirements for Gravity Lines
    B. Reporting Requirements for Gathering Lines
    C. Pipelines Affected by Extreme Weather and Natural Disasters
    D. Periodic Assessment of Pipelines Not Subject to IM
    E. IM and Non-IM Repair Criteria
    F. Leak Detection Requirements
    G. Increased Use of ILI Tools in HCAs
    H. Clarifying Other Requirements
V. PIPES Act of 2016
VI. Section-by-Section Analysis
VII. Regulatory Notices

I. Executive Summary

A. Purpose of the Regulatory Action

    In recent years, there have been significant hazardous liquid 
pipeline accidents, most notably the 2010 crude oil spill near 
Marshall, MI, during which at least 843,000 gallons of crude oil were 
released, significantly affecting the Kalamazoo River. In response to 
accident investigation findings, incident report data and trends, and 
stakeholder input, the Pipeline and Hazardous Materials Safety 
Administration (PHMSA) is amending the hazardous liquid pipeline safety 
regulations to improve protection of the public, property, and the 
environment by closing regulatory gaps where appropriate and ensuring 
that operators are increasing the detection and remediation of pipeline 
integrity threats, and mitigating the adverse effects of pipeline 
failures. On October 18, 2010, PHMSA published an Advanced Notice of 
Proposed Rulemaking (ANPRM) in the Federal Register (75 FR 63774). The 
ANPRM solicited stakeholder and public input and comments on several 
aspects of the hazardous liquid pipeline regulations being considered 
for revision or updating to address various pipeline safety issues.
    Subsequently, Congress enacted the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (2011 Pipeline 
Safety Act). That legislation included several provisions that are 
relevant to the regulation of hazardous liquid pipelines. The 2011 
Pipeline Safety Act included mandates for PHMSA to complete studies on 
topics including existing Federal and State regulations for gathering 
lines, on automatic shutdown and remote control valves, expanding 
integrity management requirements beyond high-consequence areas, and on 
the leak detection systems used by hazardous liquid operators. PHMSA 
completed these studies and submitted the valve and leak detection 
studies to Congress on December 27, 2012; the gathering line study to 
Congress on May 8, 2015; and the integrity management (IM) study in 
April of 2016. These studies are available in the docket for this 
rulemaking.
    Shortly after the 2011 Pipeline Safety Act was passed, the National 
Transportation Safety Board (NTSB) issued its accident investigation 
report on the Marshall, MI, accident on July 10, 2012. In it, the NTSB 
made recommendations regarding the need to revise and update hazardous 
liquid pipeline regulations. Specifically, the NTSB issued 
recommendations P-12-03 and P-12-04, which addressed detection of 
pipeline cracks and ``discovery of condition,'' respectively. The 
``discovery of condition'' recommendation would require, in cases where 
a determination about pipeline threats has not been obtained within 180 
days following the date of inspection, that pipeline operators notify 
PHMSA and provide an expected date when adequate information will 
become available.
    The Government Accounting Office (GAO) also issued a recommendation 
in 2012 concerning hazardous liquid and gas gathering pipelines. 
Recommendation GAO-12-388, dated March 22, 2012, states, ``To enhance 
the safety of unregulated onshore hazardous liquid and gas gathering 
pipelines, the Secretary of Transportation should direct the PHMSA 
Administrator to collect data from operators of federally unregulated 
onshore hazardous liquid and gas gathering pipelines, subsequent to an 
analysis of the benefits and industry burdens associated with such data 
collection.''
    On October 13, 2015, PHMSA published a NPRM to seek public comments 
on proposed changes to the hazardous liquid pipeline safety regulations 
(80 FR 61609). A summary of those proposed changes is provided later in 
this document.
    Between the publication of the NPRM and this final rule, the 
President signed the ``Protecting our Infrastructure of Pipelines and 
Enhancing Safety Act of 2016'' (PIPES Act of 2016), Public Law 114-183, 
on June 22, 2016. While the PIPES Act of 2016 contained several 
mandates that must be addressed

[[Page 52261]]

through rulemaking, certain provisions are self-executing standards 
that can be incorporated into this final rule rulemaking without a 
prior NPRM and opportunity to comment. Those changes are outlined in 
Section V of this document.

B. Summary of the Major Provisions of the Regulatory Action

    In response to these mandates, recommendations, lessons learned, 
and public input, PHMSA is making certain amendments to the Pipeline 
Safety Regulations affecting hazardous liquid pipelines. The first and 
second amendments extend reporting requirements to certain hazardous 
liquid gravity and rural gathering lines not currently regulated by 
PHMSA. The collection of information about these lines, including those 
that are not currently regulated, is authorized under the Pipeline 
Safety Laws, and the resulting data will assist in determining whether 
the existing Federal and State regulations for these lines and the 
scope of their applicability are adequate.
    The third amendment requires inspections of pipelines in areas 
affected by extreme weather or natural disasters that could impose 
unexpected longitudinal or circumferential pipe loads, or other risks 
to the pipeline's integrity and continued safe operation. This 
provision affects all covered lines under Sec.  195.1, whether they be 
onshore or offshore, and in a high consequence area (HCA) or outside an 
HCA.\1\ Such inspections will help to ensure that operators can safely 
operate pipelines after these events.
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    \1\ High Consequence Areas are defined in 49 CFR 195.450.
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    The fourth amendment requires integrity assessments at least once 
every 10 years, using inline inspection tools or other technology, as 
appropriate for the threat being assessed, of onshore, piggable, 
hazardous liquid pipeline segments located outside of HCAs. Existing 
regulations require operators to assess hazardous liquid pipeline 
segments located inside HCAs at least once every 5 years. These 
assessments will provide important information to operators about the 
condition of these pipelines, including the existence of internal and 
external corrosion and deformation anomalies.
    The fifth amendment extends the required use of leak detection 
systems beyond HCAs to all regulated hazardous liquid pipelines, except 
for offshore gathering and regulated rural gathering pipelines. The use 
of such systems will help to mitigate the effects of hazardous liquid 
pipeline failures that occur outside of HCAs.
    The sixth amendment requires that all pipelines in or affecting 
HCAs be capable of accommodating in-line inspection tools within 20 
years, unless the basic construction of a pipeline cannot be modified 
to permit that accommodation. In-line inspection tools are an effective 
means of assessing the integrity of a pipeline and broadening their use 
will improve the detection of anomalies and prevent or mitigate future 
accidents in high-risk areas. Finally, PHMSA is clarifying other 
regulations and is incorporating Sections 14 and 25 of the PIPES Act of 
2016 to improve regulatory certainty and compliance.

C. Cost and Benefits

    Consistent with Executive Orders 12866 and 13563, PHMSA has 
prepared an assessment of the benefits and costs of the rule as well as 
reasonably feasible alternatives. PHMSA estimates that up to 502 
hazardous liquid operators may incur costs to comply with the NPRM. The 
estimated annual costs for individual components of the requirements in 
this rulemaking range between approximately $5,000 and $10.5 million, 
with aggregate costs of approximately $19.5 million to $21.4 million 
for all requirements.\2\
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    \2\ Estimated costs are annualized using a 7 percent discount 
rate.
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    This final rule is primarily designed to mitigate or prevent 
hazardous liquid pipeline incidents, and is expected to reduce pipeline 
incident damages, including injuries and fatalities, cleanup and 
response costs, property damage, product loss, and ecosystem impacts. 
The rule's information reporting requirements are designed to provide 
PHMSA information to inform regulatory decision-making. The Regulatory 
Impact Analysis (RIA) for this final rule is available in the docket. 
The table below provides a summary of the estimated costs and benefits 
for each of the eight major provisions and in total (see the RIA for 
the details of these estimates).

                          Annualized Costs and Benefits by Requirement Area (2017$) \3\
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                                                    Annual costs \1\
  Final rule requirement area   --------------------------------------------------------         Benefits
                                      3% discount rate            7% discount rate
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1. Reporting requirements for    $5,000....................  $5,000....................  Better risk
 gravity lines.                                                                           understanding and
                                                                                          management.\2\
2. Reporting requirements for    $75,000...................  $76,000...................  Better risk
 gathering lines.                                                                         understanding and
                                                                                          management.\3\
3. Inspections of pipelines in   Minimal...................  Minimal...................  Additional clarity and
 areas affected by extreme                                                                certainty for pipeline
 weather events or natural                                                                operators.
 disasters \4\.
4. Assessments of onshore        $6,467,000................  $6,467,000................  Avoided incidents and
 pipelines that are not already                                                           damages through
 covered under the IM program                                                             detection of safety
 using ILI every 10 years 5 6.                                                            conditions.\7\
5. IM repair criteria \8\......  $0........................  $0........................  $0.
6. LDSs on pipelines located     $8,652,000................  $10,508,000...............  Reduced damages through
 outside HCAs \6\.                                                                        earlier detection and
                                                                                          response.\9\
7. Increased use of ILI tools    Minimal...................  Minimal...................  Improved detection of
 \10\.                                                                                    pipeline flaws.\10\
8. Clarify certain IM plan       $4,269,000................  $4,343,000................  Reduced damages through
 requirements.                                                                            prevention and earlier
                                                                                          detection and
                                                                                          response.\11\
                                --------------------------------------------------------------------------------
    Total......................  $19,468,000...............  $21,399,000...............  Reduced damages from
                                                                                          avoiding and/or
                                                                                          mitigating hazardous
                                                                                          liquid releases.
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\1\ Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in
  individual sections of the document. One-time costs are annualized over a 10-year period using discount rates
  of 3 percent and 7 percent.
\2\ Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow
  pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of
  this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated
  gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
  101 gallons per year to generate benefits that equal the costs.

[[Page 52262]]

 
\3\ The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated
  gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
  1,493 gallons per year to generate benefits that equal the costs.
\4\ To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting
  inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not
  reflected in this analysis.
\5\ PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not
  currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios:
  (1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a
  scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two
  scenarios are $0 and $12.9 million, respectively.
\6\ Excludes gathering lines.
\7\ Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to
  prevent 12 incidents for benefits to equate costs.
\8\ PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or
  benefits.
\9\ As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an
  average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of
  approximately $382,179, not including additional damages and costs that are excluded or underreported in the
  incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents.
\10\ Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the
  extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be
  minimal due to baseline prevalence of ILI-capable pipelines in all areas.
\11\ The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids
  cannot be quantified but could vary in frequency and size depending on the types of failures that are averted.
  Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected
  to enhance an operator's ability to identify and address risk. The societal costs associated with incidents
  involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates
  for this requirement are equivalent to the average damages from less than three such incidents. This is
  relative to an annual average of 161 incidents in HCAs between 2010 and 2017.

II. Background
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    \3\ Numbers in this table may not sum due to rounding.
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A. Detailed Overview

    This final rule addresses the requirements established by Congress 
in the 2011 Pipeline Safety Act, which are consistent with the emerging 
needs of the Nation's hazardous liquid pipeline system. This final rule 
also advances an important safety need to adapt and expand risk-based 
safety practices considering changing markets and a growing national 
population whose location choices are in ever-closer proximity to 
existing pipelines.
    This final rule strengthens protocols for IM, including protocols 
for inspections, and improves and streamlines information collection to 
help drive risk-based identification of the areas with the greatest 
safety deficiencies.
Hazardous Liquid Infrastructure Overview
    There are two major types of pipelines along the petroleum 
transportation route: Gathering pipeline systems, and crude oil and 
refined products pipeline systems. The location, construction and 
operation of these systems are generally regulated by Federal and State 
requirements.
    Gathering lines are typically smaller pipelines no more than 8\5/8\ 
inches in diameter that transport petroleum from onshore and offshore 
production facilities. Hazardous liquid pipelines transport the crude 
oil from the gathering systems to refineries and from refineries to 
distribution centers. Hazardous liquid lines transport both crude and 
refined products, and can be hundreds of miles long. These lines may 
cross State and continental borders, and range in size from 2 to 48 
inches in diameter. Hazardous liquid pipeline networks also include 
pump stations, which move the product through the pipelines, and 
storage terminals. Changes in product demand has also led to efforts by 
operators to increase pipeline capacity through flow-direction 
reversals or converting natural gas pipelines into hazardous liquid 
pipelines.
    Per PHMSA's database, 43 percent of all hazardous liquid pipelines 
were installed prior to 1970.\4\ However, pipeline manufacturing, 
construction, and operational and maintenance practices have been 
improving steadily in recent decades, and some older pipes are 
susceptible to certain manufacturing or construction defects. For 
example, low-frequency electric resistance welded (ERW) pipe used from 
the early 1900s through the post-World War II construction boom that 
lasted well into the 1970s is vulnerable to seam-quality issues. Since 
the early 1970s, many improvements in pipe manufacturing and materials 
have been made, and steel and seam properties of pipe have improved 
with the increased use of high-frequency electric welded (HF-ERW), 
submerged arc welded (SAW), and seamless pipe (SMLS).\5\ In addition, 
smart pigs, which are tools that record information about the internal 
conditions of a pipeline, were not developed until the 1960s and 1970s 
prior to the adoption of the part 195 regulations.
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    \4\ PHMSA's Annual Report Mileage for Hazardous Liquid or Carbon 
Dioxide Systems; https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
    \5\ HF-ERW steel pipe has a welded pipe seam made using a high 
frequency welding current. SMLS steel pipe has no longitudinal weld 
seam. SAW steel pipe has a weld seam made using a submerged welding 
arc in a bed of powdered flux to shield it from impurities.
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    Since 2012, U.S. oil production has increased about 70 percent from 
approximately 2.4 to 3.4 Billion barrels annually \6\ resulting in the 
United States becoming the world's largest producer of liquid fuels in 
early 2014. Much of the recent increases in production have been in 
tight oil plays. Tight oil shale formations are heterogeneous and vary 
widely over relatively short distances and are subjected to fracking. 
Examples of tight oil formations include the Bakken Shale, the Niobrara 
Formation, Barnett Shale, and the Eagle Ford Shale in the United 
States. Per data from the U.S. Energy Information Administration (EIA), 
in 2017, tight oil plays accounted for approximately half of the U.S. 
production, balancing declining production in older plays. While tight 
oil from shale plays has historically been more difficult to extract, 
improvements in drilling and production methods, such as horizontal 
drilling and hydraulic fracturing, have made it economically 
recoverable. These tight oil plays are located both in regions that 
have had an oil extraction industry for decades and new regions, such 
as the Bakken region in North Dakota and Montana, that were not 
previously oil-producing areas. This has expanded U.S. refiners' access 
to domestically produced crudes, and U.S. crude oil imports dropped by 
7 percent since 2012.\7\ Additionally, exports have risen from minimal 
amounts in 2012 to

[[Page 52263]]

over a million barrels per day in 2017.\8\ These supply increases and 
spatial changes in production patterns are creating wide-ranging 
impacts on liquid fuels transportation infrastructure.
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    \6\ U.S. Energy Information Administration, Crude Oil 
Production. Producers extracted 2.4 billion barrels of crude oil 
from U.S. fields in 2012 and 3.4 billion barrels of crude oil in 
2017. https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm.
    \7\ EIA, U.S. Imports of Crude Oil (Thousands of Barrels per 
Day). https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbblpd_a.htm.
    \8\ EIA, U.S. Exports of Crude Oil (Thousand Barrels per Day). 
https://www.eia.gov/dnav/pet/pet_move_exp_dc_NUS-Z00_mbblpd_a.htm.
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Regulatory History
    Congress established the current framework for regulating the 
safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline 
Safety Act (HLPSA) of 1979 (Pub. L. 96-129). The HLPSA provides the 
Secretary of Transportation (the Secretary) with the authority to 
prescribe minimum Federal safety standards for hazardous liquid 
pipeline facilities. That authority, as amended in subsequent 
reauthorizations, is currently codified in the Pipeline Safety Laws (49 
U.S.C. 60101, et seq.).
    PHMSA is the agency within DOT that administers the Pipeline Safety 
Laws. PHMSA has issued a set of comprehensive safety standards for the 
design, construction, testing, operation, and maintenance of hazardous 
liquid pipelines. Those standards are codified in the Hazardous Liquid 
Pipeline Safety Regulations (49 CFR part 195).
    Part 195 applies broadly to the transportation of hazardous liquids 
or carbon dioxide by pipeline, including on the Outer Continental 
Shelf, with certain exceptions set forth by statute or regulation. A 
combination of prescriptive and management-based safety standards is 
used (i.e., an objective is specified, but the method of achieving that 
objective is not). Risk management principles play a key role in the IM 
requirements.
    PHMSA exercises primary regulatory authority over interstate 
hazardous liquid pipelines, and the owners and operators of those 
facilities must comply with safety standards in part 195. States may 
apply to PHMSA for a certification to conduct inspections of intrastate 
hazardous liquid pipelines. Public utility commissions administer most 
State pipeline safety programs. These State authorities must adopt the 
Pipeline Safety Regulations as part of a certification or agreement 
with PHMSA, but may establish more stringent safety standards for 
intrastate pipeline facilities within their State regulatory 
authorities. PHMSA is precluded from regulating the safety standards or 
practices for an intrastate pipeline facility if a State is currently 
certified to regulate that facility. States certified to regulate their 
intrastate lines can also enter into agreements with PHMSA to serve as 
an agent for inspecting interstate facilities, and they can receive 
Federal monetary grants to off-set the costs of those State 
inspections.
    In 2000 and 2002, the Office of Pipeline Safety (OPS) published 
regulations requiring IM programs for hazardous liquid pipeline 
operators in response to a hazardous liquid incident in Bellingham, WA, 
in 1999 that killed three people.\9\ The regulations were broad-
reaching and supplemented PHMSA's prescriptive safety requirements with 
performance and process-oriented requirements. The approach aimed to 
set expectations for operators while giving them a degree of 
flexibility in how they complied with those expectations. The 
objectives of the IM regulations were to accelerate and improve the 
quality of integrity assessments conducted on pipelines in areas with 
the highest potential for adverse consequences; promote a more 
rigorous, integrated, and systematic management of pipeline integrity 
and risk by operators; strengthen the government's role in the 
oversight of pipeline operator integrity plans and programs; and 
increase the public's confidence in the safe operation of the Nation's 
pipeline network.
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    \9\ 65 FR 75378; December 1, 2000; Pipeline Safety: Pipeline 
Integrity Management in High Consequence Areas (Hazardous Liquid 
Operators With 500 or More Miles of Pipeline). 67 FR 1650; January 
14, 2002; Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Repair Criteria). 67 FR 2136; January 16, 2002; 
Pipeline Safety: Pipeline Integrity Management in High Consequence 
Areas (Hazardous Liquid Operators With Less Than 500 Miles of 
Pipelines).
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    In January 2011, PHMSA published the Hazardous Liquid Integrity 
Management Progress Report,\10\ which reported on PHMSA's progress in 
achieving the program objectives and examined accident trends. The 
report found that the IM rule and PHMSA's rigorous oversight of 
operator compliance with the rule are contributing to improved safety 
performance, including a reduction in the frequency of significant 
accidents and a decrease in volume spilled in significant accidents.
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    \10\ http://primis.phmsa.dot.gov/iim/IM_Jan2011_StatusReport_01_23_11.pdf.
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PHMSA's Progress on Integrity Management
    The original part 195 Pipeline Safety Regulations were not designed 
with risk management in mind. In the mid-1990s, following models from 
other industries such as nuclear power, PHMSA started to explore 
whether a risk-based approach to regulation could improve safety of the 
public and the environment. During this time, PHMSA found that many 
operators were performing forms of IM that varied in scope and 
sophistication but there were not consistent minimum standards or 
requirements.
    Since the implementation of the IM regulations more than 15 years 
ago, many factors have changed. Most importantly, there have been 
sweeping changes in the oil industry, and the Nation's relatively safe 
but aging pipeline network faces increased pressures from these 
changes. Long-identified pipeline safety issues, some of which IM set 
out to address, remain problems. Infrequent but severe accidents 
indicate that some pipelines continue to be vulnerable to failures 
stemming from, among other things, outdated construction methods or 
materials. Some severe pipeline accidents have occurred in areas 
outside HCAs where the application of IM principles is not 
required.\11\
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    \11\ Per PHMSA annual report data accessed May 14, 2019, 1677 
non-HCA accidents have occurred since 2010. Of these accidents, 908 
resulted in a ``large'' spill, which for reporting purposes is 
defined as those spills where there was a fatality, injury, fire, 
explosion, water contamination, property damage of greater than 
$50,000, or an unintentional loss of product greater than 210 
gallons (5 bbls).
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    The current IM program is both a set of regulations and an overall 
regulatory approach to improve pipeline operators' ability to identify 
and mitigate the risks to their pipeline systems. On the operator 
level, an IM program includes adopting procedures and processes to 
identify HCAs, which are areas with the greatest population density and 
environmental sensitivity; determining likely threats to the pipeline 
within the HCA; evaluating the physical integrity of the pipe within 
the HCA; and repairing or remediating any pipeline defects found. 
Because these procedures and processes are complex and interconnected, 
effective implementation of an IM program relies on continual 
evaluation and data integration.
    Operators have made great progress towards achieving the IM 
objectives. Operators have an improved understanding of the precise 
locations of their HCAs--those areas where integrity assessments and 
other protective measures spelled out in the IM rule must be taken to 
assure public safety and environmental protection. During an incident, 
petroleum can spread over large areas and cause environmental damage. 
The IM protections for HCAs are designed to account for the potential 
environmental and community risks from oil releases. Per PHMSA's 
hazardous liquid annual

[[Page 52264]]

data, 42 percent of the Nation's hazardous liquid pipelines \12\ can 
potentially affect HCAs and thus receive the enhanced level of 
integrity assessment and protection mandated by the IM rule. As 
required by the IM rule, operators have also conducted baseline 
integrity assessments on all pipelines that could affect HCAs and have 
begun conducting reassessments of these same pipeline segments. Through 
this requirement to assess their pipelines, operators now have an 
improved understanding of the condition of pipelines in these safety-
sensitive areas.
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    \12\ http://phmsa.dot.gov/portal/site/PHMSA/menuitem.6f23687cf7b00b0f22e4c6962d9c8789/?vgnextoid=a872dfa122a1d110VgnVCM1000009ed07898RCRD&vgnextchannel=3430fb649a2dc110VgnVCM1000009ed07898RCRD&vgnextfmt=print.
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    According to PHMSA's January 2011 Hazardous Liquid Integrity 
Management Progress Report, which tracked the progress and 
effectiveness of the IM program in its first decade, as a result of 
these initial baseline assessments, operators have made more than 7,600 
repairs of anomalies that required immediate attention, remediated over 
28,000 other conditions on a scheduled basis, and addressed an 
additional 79,000 anomalies that were not required to be addressed by 
the IM rule, thus significantly improving the condition of the Nation's 
pipelines.
    However, based on recent accidents and mandates from the 2011 
Pipeline Safety Act, improvement is still needed in the areas of data 
integration and their use in risk modelling, risk analysis, and to 
identify and implement additional preventive and mitigative measures to 
reduce risk. Improving data integration is critical, as the integrity 
assessment provisions of the rule only address some of the causes of 
pipeline failures.
Inadequate Leak Detection, Exposure to Weather, Increased Use, and Age 
Can Increase the Risk of Pipeline Incidents
    Risk factors for pipeline safety issues stem from many sources, 
including manufacturing issues, external weather and environmental 
factors, land-use activities near pipelines, other operational issues, 
and age-related integrity issues.
    On July 25, 2010, a segment of a 30-inch-diameter pipeline called 
Line 6B, owned and operated by Enbridge Incorporated, ruptured in a 
wetland area in Marshall, MI. Per Sec. Sec.  195.450 and 195.6, this 
area was identified by the operator as an ``other populated area,'' 
which meant it was within an HCA. Per the NTSB's Pipeline Accident 
Report on the incident, the rupture occurred during the last stages of 
a planned shutdown and was not discovered or addressed for over 17 
hours. During the time lapse, Enbridge twice pumped additional oil (81 
percent of the total release) into Line 6B during two startups; the 
total release was estimated by Enbridge to be 843,444 gallons of crude 
oil.\13\ The oil saturated the surrounding wetlands and flowed into the 
Talmadge Creek and the Kalamazoo River. In all, 4,632 acres of land 
were impacted, 346 animals were killed, 4,208 animals were oiled, and 
fish and benthic invertebrate communities were impacted. Further, 
approximately 100,000 recreational user-days were lost, including 
activities like fishing and boating, and general shoreline park and 
trail use. The incident also resulted in losses of tribal use, as the 
Kalamazoo River is used by two tribes for water travel; subsistence; 
and medicinal, economic, educational, and ceremonial services.\14\ This 
incident motivated a reexamination of hazardous liquid pipeline safety. 
The NTSB made recommendations to PHMSA and the regulated industry 
regarding the need to improve hazardous liquid pipeline safety. 
Congress also directed PHMSA to reexamine many of its safety 
requirements, including the expansion of IM regulations to more 
hazardous liquid pipelines. Other recent accidents, including a pair of 
related failures that occurred in 2010 on a crude oil pipeline in Salt 
Lake City, UT, corroborated the significance of having an adequate 
means for identifying and responding to leaks in all locations.
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    \13\ National Transportation Safety Board: ``Enbridge 
Incorporated Hazardous Liquid Pipeline Rupture and Release, 
Marshall, Michigan, July 25, 2010,'' Accident Report NTSB/PAR-12/01, 
adopted 2012; http://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf.
    \14\ U.S. Fish and Wildlife Service: ``Final Damage Assessment 
and Restoration Plan/Environmental Assessment for the July 25-26, 
2010 Enbridge Line 6B Oil Discharges near Marshall, MI;'' Sections 
1.4--Summary of Natural Resource Injuries and 3.0--Injury Assessment 
and Quantification. October 2015. https://www.fws.gov/midwest/es/ec/nrda/MichiganEnbridge/pdf/FinalDARP_EA_EnbridgeOct2015.pdf.
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    The Nation's pipeline system also faces significant risk from 
failure due to extreme weather events and natural disasters, such as 
hurricanes, floods, mudslides, tornadoes, and earthquakes. On January 
17, 2015, a breach in the Bridger Pipeline Company's Poplar system 
resulted in a spill into the Yellowstone River near the town of 
Glendive, MT, releasing 31,835 gallons (758 barrels) \15\ of crude oil 
into the river and affecting local water supplies. Information 
indicated over 100 feet of pipeline was exposed on the river bottom, 
and the release point was near a girth weld. A depth of cover survey 
indicated sufficient cover in late 2011,\16\ but the area experienced 
localized flooding in early 2014. A previous crude oil spill into the 
Yellowstone River in 2011 near Laurel, MT, was caused by channel 
migration and river bottom scour, leaving a large span of the pipeline 
exposed to prolonged current forces and debris washing downstream in 
the river. Those external forces damaged the exposed pipeline.
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    \15\ PHMSA Database: ``Operator Information: Incident and 
Mileage Data: Bridger Pipeline LLC,'' http://primis.phmsa.dot.gov/comm/reports/operator/OperatorIM_opid_31878.html?nocache=4851%20-%20_Incidents_tab_3#_OuterPanel_tab_2.
    \16\ PHMSA, Corrective Action Order, CPF No. 5-2015-5003H, page 
4, January 23, 2015; http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Pipeline/520155003H_Corrective%20Action%20Order_01232015.pdf.
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    In October 1994, flooding along the San Jacinto River led to the 
failure of eight hazardous liquid pipelines and undermined a number of 
other pipelines. The escaping products were ignited, leading to 547 
people in the area suffering extensive smoke inhalation or burn 
injuries.\17\ According to PHMSA's Accident and Incident Data for 
hazardous liquid pipelines, from 2010 to 2017, there were 145 
reportable incidents \18\ in which storms or other severe natural force 
conditions damaged pipelines and resulted in their failure. Operators 
reported total damages of over $232 million from these incidents.\19\ 
PHMSA has issued several Advisory Bulletins to operators warning about 
extreme weather events and the consequences of flooding events, 
including river scour and river channel migration. Further, in December 
2017, the American Petroleum Institute issued a Recommended Practice 
1133 that provided guidance to operators on how to identify at-risk 
river crossings and take measures to reduce such risks before, during, 
and after flooding- and river-scour events.
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    \17\ NTSB, Pipeline Special Investigation Report, ``Evaluation 
of Pipeline Failures During Flooding and of Spill Response Actions, 
San Jacinto River Near Houston, Texas, October 1994;'' NTSB/SIR-96/
04, Adopted September 6, 1996.
    \18\ Reporting thresholds for hazardous liquid pipelines are 
established at Sec.  195.50. Operators must report any failures of a 
hazardous liquid pipeline resulting in any of the following: (1) An 
explosion or fire not intentionally set by the operator, (2) A 
release of 5 gallons or more of hazardous liquid or carbon dioxide, 
(3) The death of an individual, (4) Personal injury requiring 
hospitalization, (5) Estimated property damage exceeding $50,000.
    \19\ PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
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    In addition to external weather and environmental threats, changing 
production and shipment patterns are increasing stress on the Nation's

[[Page 52265]]

pipeline system. Shifting production to tight oil production like shale 
plays have changed U.S. oil production locations, as well as the types 
of crude transported in the Nation's pipelines. The U.S. pipeline 
system has previously moved crude oil from interior production regions 
to the Gulf of Mexico refineries, and petroleum products from Gulf 
Coast refineries to the interior of the country. However, increased 
tight oil production requires significant infrastructure expansion in 
new areas, and shifting production areas are changing the patterns of 
oil transport. Many operators are adapting their systems to move crude 
oil to markets formerly dependent on imports by modifying existing 
pipelines. These modifications can be made by reversing flow directions 
and repurposing natural gas pipelines; in some cases pipeline expansion 
projects can also increase pumping capability with minimal alterations 
of the pipeline itself.
    Reversing a pipeline's flow, modifying pump station placement and 
operation, changing commodities, or making other changes to a 
pipeline's historical hydraulic gradient can impose new stresses on the 
system due to altered pressure gradients, cycling, and flow rates. 
Furthermore, certain commodities and low flow rates may create new 
risks of internal corrosion. Occasional failures on hazardous liquid 
pipelines have occurred after operational changes that include flow 
reversals and product changes. PHMSA has noticed several recent or 
proposed flow reversals and product changes on a number of hazardous 
liquid and gas transmission lines. In response to this phenomenon, on 
September 18, 2014, PHMSA issued an Advisory Bulletin \20\ notifying 
operators of the potentially significant impacts such changes may have 
on the integrity of a pipeline.
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    \20\ PHMSA: ``Pipeline Safety: Guidance for Pipeline Flow 
Reversals, Product Changes and Conversion to Service'' Advisory 
Bulletin, 79 FR 56121, September 18, 2014; http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Advisory%20Notices/ADB-2014-04_Flow_Reversal.pdf.
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    Data indicate that some pipelines also continue to be vulnerable to 
issues stemming from outdated construction methods or materials. Much 
of the older pipe in the Nation's pipeline infrastructure was made 
before the 1970s using techniques that have proven to contain latent 
defects due to the manufacturing process.\21\ Such defects cause the 
pipe to be susceptible to developing hook cracks or other anomalies 
that may, over time, lead to failures if they are not timely repaired. 
For example, line pipe manufactured using low-frequency electric 
resistance welding is susceptible to seam failure. A substantial amount 
of this type of pipe is still in service; per PHMSA's ``Miles by Decade 
of Installation Inventory Reports'' for hazardous liquid lines, there 
were 92,271 miles of pre-1970s pipe still in service in 2017.\22\ The 
IM regulations include specific requirements for evaluating such pipe 
if located in HCAs, but infrequent-yet-severe failures that are 
attributed to longitudinal seam defects continue to occur. Per PHMSA's 
Accident and Incident database, between 2010 and 2017, 84 reportable 
incidents were attributed to seam failures, resulting in over $220 
million of property damage.23 24
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    \21\ See https://primis.phmsa.dot.gov/comm/FactSheets/FSPipeManufacturingProcess.htm for more information about pipe 
manufacturing processes and known latent defects.
    \22\ PHMSA's Annual Report Mileage for Hazardous Liquid or 
Carbon Dioxide Systems; https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
    \23\ PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
    \24\ The data can be narrowed down by selecting the 
``hl2010toPresent'' Excel spreadsheet. Cell ``CR'' indicates the 
identified location of the failure and whether the failure was in 
the pipe body or in the pipe seam. If it was identified as a pipe 
seam failure, Cells ``CW'' and ``CX'' provide additional information 
on pipe seam type and pipe seam details, respectively.
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    In the final rule, PHMSA strengthens the IM requirements to 
identify and respond to the increased pipeline risks resulting from 
operational changes, weather and associated geotechnical hazards, and 
increased use and age of a pipe.
Enhanced Collection of Data
    To keep the public safe and to protect the Nation's energy security 
and reliability, operators and regulators must have an intimate 
understanding of their entire pipeline system, including threats and 
operations. However, with operators who are not required to report 
certain information on certain currently unregulated pipelines, and 
with aging pipelines that are not modernized for internal inspection, 
there continue to be data gaps that make it hard to fully understand 
the extent of the potential safety risks to the integrity of the 
Nation's pipeline system.
    PHMSA's regulations exempt rural gathering pipelines and gravity 
pipelines. Gravity pipelines carry product by means of gravity, and 
many gravity lines are short and within tank farms or other pipeline 
facilities. However, some gravity lines are longer and can build up 
high pressures. PHMSA is aware of gravity lines that traverse long 
distances with significant elevation changes, which could have 
significant consequences in the event of a release. Both gravity and 
gathering lines are currently excluded from reporting requirements, 
leaving large gaps in PHMSA's knowledge of these unregulated pipeline 
systems. This is especially true because much of operators' and PHMSA's 
data is obtained through testing and inspection under IM requirements, 
which are not currently required for gathering and gravity lines.
    To assess a pipeline's integrity, operators generally choose 
between three methods of testing a pipeline: In-line inspection (ILI), 
pressure testing, and direct assessment (DA). In 2017, PHMSA estimates 
that slightly over 90 percent of the hazardous liquid line mileage in 
HCAs is already piggable and almost 90 percent of these lines were 
being inspected with ILI tools.
    Operators perform ILIs by using special tools, sometimes referred 
to as ``smart pigs,'' which are usually pushed through a pipeline by 
the pressure and flow rate of the product being transported. As the 
tool travels through the pipeline, it identifies and records potential 
pipe defects or anomalies. Because these tests can be performed with 
product in the pipeline, the pipeline does not have to be taken out of 
service for testing to occur, which can reduce cost to the operator and 
possible service disruptions to consumers. Further, ILI is a non-
destructive testing technique, and it can be less costly on a per-unit 
basis to perform than other assessment methods. However, a very small 
portion of hazardous liquid pipe segments cannot be inspected through 
ILI because they are too short in length, which makes getting accurate 
ILI tool results impractical due to tool speed variations. Other 
hazardous liquid pipelines might not be inspected through ILI because 
they do not have enough operating pressure or flow rate to run the 
tool.
    Pipeline operators typically use pressure tests to determine the 
integrity (or strength) of the pipeline immediately after construction 
and before placing the pipeline in service. In a pressure test, a test 
medium (typically water) inside the pipeline is pressurized to a level 
greater than the normal operating pressure of the pipeline. This test 
pressure is held for a number of hours to ensure there are no leaks in 
the pipeline.
    Direct assessment is the evaluation of various locations on a 
pipeline for corrosion threats. Operators will review operational 
records and indirectly inspect the pipeline with coating surveys, such 
as close interval, direct

[[Page 52266]]

current voltage gradient, and alternating current voltage gradient 
surveys, to detect areas where the protective, anti-corrosion coating 
applied to a pipeline may be faulty, as corrosion may be more likely in 
these locations. Operators subsequently excavate and examine areas that 
are likely to have suffered from corrosion. DA can be costly to use 
without targeting specific locations. A limited number of specific 
locations, however, may not give an accurate representation of the 
condition of lengths of entire pipeline segments.
    Ongoing research appears to indicate that ILI and hydrostatic 
pressure ``spike'' testing are more effective than DA for identifying 
pipe conditions related to cracking defects such as dents with stress 
cracks, stress corrosion cracking (SCC), selective seam weld corrosion 
(SSWC), and other seam-type cracking.\25\ Hydrostatic testing of 
hazardous liquid pipelines requires testing to at least 125 percent of 
the maximum operating pressure (MOP) for at least 4 continuous hours 
and an additional 4 hours at a pressure of at least 110 percent of MOP 
if the pipe is not visible. If there is concern about pipe cracks that 
might grow due to pressure cycling, operating stress levels, 
environmental conditions, and fatigue, then a spike test at a pressure 
of up to or over 139 percent of MOP for a short period (up to a 30-
minute hold time or longer) may be conducted. A spike test detects pipe 
body and seam cracks by causing any cracks that would later grow to 
failure to fail during the hydrostatic test. Both regulators and 
operators have expressed interest in improving ILI methods as an 
alternative to hydrostatic testing for better risk evaluation and 
management of pipeline safety. Hydrostatic pressure testing can result 
in substantial costs and occasional disruptions in service, whereas ILI 
testing can obtain data that is not otherwise obtainable via other 
assessment methods, such as pipe wall loss, dents, and cracking.
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    \25\ See: Comprehensive Study to Understand Longitudinal ERW 
Seam Research & Development study task reports: Battelle Final 
Reports (``Battelle's Experience with ERW and Flash Weld Seam 
Failures: Causes and Implications''--Task 1.4), Report No. 13-002 
(``Models for Predicting Failure Stress Levels for Defects Affecting 
ERW and Flash-Welded Seams''--Subtask 2.4), Report No. 13-021 
(``Predicting Times to Failure for ERW Seam Defects that Grow by 
Pressure-Cycle-Induced Fatigue''--Subtask 2.5), and ``Final Summary 
Report and Recommendations for the Comprehensive Study to Understand 
Longitudinal ERW Seam Failures--Phase 1''--Task 4.5), which can be 
found online at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
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    In this final rule, PHMSA is addressing data gaps and increasing 
the quality of data collected by expanding the reporting requirements 
to cover both gathering and gravity lines and requiring that all lines 
in HCAs be piggable for a better understanding of pipeline 
characteristics. The final rule will also require operators to fully 
integrate their pipeline data across all data sources to close any 
remaining gaps.
Looking at Risk Beyond HCAs
    In addition to improving IM programs for the pipe that they already 
cover, PHMSA understands the importance of carefully reconsidering the 
scope of the areas covered by IM requirements. While PHMSA's hazardous 
liquid IM program manages risks primarily by focusing oversight on 
areas with the greatest population density and environmental 
sensitivity, it is imperative to protect the safety of environmental 
resources and communities throughout the country. The changing 
landscape of production, consumption, and product movement merits a 
fresh look at the current scope of IM coverage.
    The current definition of an HCA uses Census Bureau definitions of 
urbanized areas or areas with a concentrated population.\26\ The HCA 
definition also encompasses ``unusually sensitive areas,'' including 
drinking water or ecological resource areas and commercially navigable 
waterways. However, liquid spills, even outside HCAs, can result in 
environmental damage necessitating clean up, restoration costs, and 
lost use and non-use values. If operators do not periodically assess 
and repair their pipelines, liquid spills are more likely to occur. In 
fact, devastating incidents have occurred outside of HCAs in rural 
areas where populations are sparse, and operators have not been 
required to assess their lines as frequently as lines covered by IM. 
Per PHMSA's databases, between 2010 and 2017, significant incidents at 
hazardous liquid facilities accounted for over 993,097 barrels spilled, 
24 injuries, and 10 fatalities. Out of those, over 702,091 barrels 
spilled, 10 injuries, and four fatalities occurred in non-HCA 
areas.\27\ These data show that ruptures with the potential to affect 
populations, the environment, or commerce, can occur anywhere on the 
Nation's pipeline system.
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    \26\ Specifically, Sec.  195.450 states that a high population 
area is an urban area, as defined and delineated by the Census 
Bureau, that contains 50,000 or more people and has a population 
density of at least 1,000 people per square mile, and an other 
populated area is a place, as defined and delineated by the Census 
Bureau, that contains a concentrated population, such as an 
incorporated or unincorporated city, town, village, or other 
designated residential or commercial area.
    \27\ PHMSA Hazardous Liquid Accident Reports. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
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    If constant improvement and zero incidents are goals for pipeline 
operators,\28\ extending and prioritizing IM assessments and principles 
to all parts of pipeline networks is an effective way to achieve those 
goals. Extending IM assessments and principles to non-HCAs will help 
clarify vulnerabilities and prioritize improvements, and this final 
rule takes important steps towards developing that approach and will 
lead operators to gather valuable information they may not have 
collected if regulations were not in place.
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    \28\ Major trade associations, including API and INGAA, have 
publicly committed to a goal of zero incidents. See: https://www.api.org/oil-and-natural-gas/wells-to-consumer/transporting-oil-natural-gas/pipeline/pipeline-safety and https://www.ingaa.org/File.aspx?id=20463 for more details.
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    In this final rule, PHMSA is requiring operators to assess onshore, 
piggable pipelines outside of HCAs periodically using ILI or other 
technology, if appropriate, to detect (and remediate) anomalies in all 
locations within their pipeline systems. PHMSA is providing operators 
with deadlines to verify their segment analyses to identify any new 
HCAs and implement the appropriate actions. These changes would ensure 
the remediation of anomalous conditions that could potentially impact 
people, property, or the environment, while at the same time allowing 
operators to allocate their resources based on pipeline risks and the 
vulnerability of surrounding areas.
Recent Developments in Hazardous Liquid Pipeline Safety Regulation
    On October 18, 2010, PHMSA posed a series of questions to the 
public in the context of an ANPRM titled ``Pipeline Safety: Safety of 
On-Shore Hazardous Liquid Pipelines'' (75 FR 63774). In that document, 
PHMSA sought comments on several proposed changes to part 195, 
including: (1) The scope of part 195 and existing regulatory 
exceptions, (2) Criteria for designation of HCAs, (3) Leak detection 
and emergency flow restricting devices, (4) Valve spacing, (5) Repair 
criteria outside of HCAs, and (6) Stress corrosion cracking. The 
questions in this ANPRM considered topics relating to the statutory 
mandates; the post-Marshall, MI, NTSB and GAO recommendations; and 
other pipeline safety mandates. Twenty-one organizations and 
individuals submitted comments in response to the ANPRM.
    PHMSA reviewed the received comments, the 2011 Pipeline Safety Act,

[[Page 52267]]

and the NTSB and GAO recommendations, and responded in the subsequent 
NPRM published on October 13, 2015, (80 FR 61609). In summary, the NPRM 
addressed the following areas: (1) Reporting requirements for gravity 
lines, (2) Reporting requirements for gathering lines, (3) Inspections 
of pipelines following extreme weather events and natural disasters, 
(4) Periodic assessments of pipelines not subject to IM, (5) Repair 
criteria, (6) Expanded use of leak detection systems, (7) Increased use 
of in-line inspection tools, and (8) Clarifying other requirements. A 
summary of comments and responses to those comments are provided later 
in the document. The ANPRM and NPRM may be viewed at http://www.regulations.gov by searching for Docket No. PHMSA-2010-0229.

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

    After the issuance of the ANPRM on October 18, 2010, the 2011 
Pipeline Safety Act included several statutory requirements related 
directly to the topics being considered in the ANPRM. The related 
topics and statutory citations that PHMSA considered within the context 
of this rulemaking include, but are not limited to:
     Section 5(f)--Requires, if appropriate, regulations issued 
by the Secretary to expand integrity management system requirements, or 
elements thereof, beyond high-consequence areas. These regulations are 
to be dependent on an evaluation and report of whether integrity 
management system requirements, or elements thereof, should be expanded 
beyond high-consequence areas;
     Section 8--Requires, if appropriate, regulations regarding 
leak detection on hazardous liquid pipelines and establishing leak 
detection standards. These regulations are to be dependent on a report 
on the analysis of the technical limitations of current leak detection 
systems, including the ability of the systems to detect ruptures and 
small leaks that are ongoing or intermittent, and what can be done to 
foster development of better technologies, and an analysis of the 
practicability of establishing technically, operationally, and 
economically feasible standards for the capability of such systems to 
detect leaks, and the safety benefits and adverse consequences of 
requiring operators to use leak detection systems;
     Section 14--Permits PHMSA to issue regulations for 
pipelines transporting non-petroleum fuels, such as biofuels;
     Section 21--Requires a review on the regulation of Gas 
(and Hazardous Liquid) Gathering Lines and the issuance of further 
regulations, if appropriate; and
     Section 29--Requires that operators consider seismicity 
when evaluating pipeline threats.

C. National Transportation Safety Board Recommendation

    On July 10, 2012, shortly after the 2011 Pipeline Safety Act was 
passed, the NTSB issued its accident investigation report on the 
Marshall, MI, accident. In it, the NTSB made additional recommendations 
to update the hazardous liquid pipeline regulations. Pertaining 
directly to this rule, the NTSB issued recommendation P-12-04, which 
addressed the ``discovery of condition'' as follows:
     NTSB Recommendation P-12-4: ``Revise Title 49 Code of 
Federal Regulations 195.452(h)(2), the `discovery of condition,' to 
require, in cases where a determination about pipeline threats has not 
been obtained within 180 days following the date of inspection, that 
pipeline operators notify the Pipeline and Hazardous Materials Safety 
Administration and provide an expected date when adequate information 
will become available.''

D. Summary of Each Topic

    This final rule amends the Federal Pipeline Safety Regulations to 
address the following topics. Details of the changes in this rule are 
discussed in this document in Section IV, ``Analysis of Comments and 
PHMSA Response,'' and Section V, ``Section-by-Section Analysis.''
(1) Extend Certain Reporting Requirements to Certain Gravity and Rural 
Hazardous Liquid Gathering Lines
    Gravity lines are pipelines that carry product by means of gravity 
and are currently exempt from PHMSA regulations. Many gravity lines are 
short and within tank farms or other pipeline facilities; however, some 
gravity lines are longer and can build up large amounts of pressure. 
Further, certain gravity lines may have significant elevation changes, 
which can lead to serious consequences in the event of a release.
    For PHMSA to effectively analyze the safety performance and risk of 
gravity lines, PHMSA needs basic data about those pipelines. The agency 
has the statutory authority to gather data for all gravity lines (49 
U.S.C. 60117(b)). Accordingly, PHMSA is amending the Pipeline Safety 
Regulations (PSR) to require that the operators of certain gravity 
lines comply with requirements for submitting annual, safety-related 
condition, and incident reports. PHMSA estimates that, at most, five 
hazardous liquid pipeline operators will be affected. Based on comments 
to the ANPRM from the American Petroleum Institute and the Association 
of Oil Pipelines (API-AOPL), 3 operators have approximately 17 miles of 
gravity-fed pipelines. PHMSA estimated that proportionally 5 operators 
would have 28 miles of gravity-fed pipelines.
    PHMSA is also amending the PSR to extend the annual, accident, and 
safety-related condition reporting requirements of part 195 to all 
hazardous liquid gathering lines. The Hazardous Liquid Pipeline Safety 
Act of 1979 (Pub. L. 96-129) did not mandate the regulation of rural 
gathering lines because at that time they were not thought to present a 
significant enough risk to public safety to justify Federal regulation 
based on the data available at that time. However, the Pipeline Safety 
Act of 1992 (Pub. L. 102-508) authorized the issuance of safety 
standards for regulated rural gathering lines based on a consideration 
of certain factors and subject to certain exclusions. When PHMSA 
adopted the current requirements for regulated rural gathering lines, 
the agency made judgments in implementing those statutory provisions 
based on the information available at that time.

[[Page 52268]]

    Recent data indicates, however, that PHMSA regulates less than 
4,000 miles of the approximately 30,000 to 40,000 miles of onshore 
hazardous liquid gathering lines in the United States.\29\ That means 
that about 90 percent of the onshore gathering line mileage is not 
currently subject to any minimum Federal pipeline safety standards. The 
NTSB has also raised concerns about the safety of hazardous liquid 
gathering lines in the Gulf of Mexico and its inlets,\30\ which are 
only subject to certain inspection and reburial requirements.
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    \29\ PHMSA, ``Hazardous Liquid Pipeline Miles and Tanks,'' 
https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?Portalpages&NQUser=PDM_WEB_USER&NQPassword=Public_Web_User1&PortalPath=%2Fshared%2FPDM%20Public%20website%2F_portal%2FPublic%20Reports&Page=Infrastructure&Action=Navigate&col1=%22PHP%20-%20Geo%20Location%22.%22State%20Name%22&val1=%22%22, retrieved 11/
20/2018.
    \30\ Deborah Hersman, Testimony before the Subcommittee on 
Surface Transportation and Merchant Marine Infrastructure, Safety, 
and Security Committee on Commerce, Science, and Transportation, 
United States Senate Hearing on Ensuring the Safety of our Nation's 
Pipelines, Washington DC, 6/24/2010. https://www.ntsb.gov/news/speeches/DHersman/Pages/Testimony_before_the_Subcommittee_on_Surface_Transportation_and_Merchant_Marine_Infrastructure_Safety_and_Security_Committ.aspx.
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    In the ANPRM, PHMSA asked whether the agency should repeal or 
modify any of the exceptions for hazardous liquid gathering lines. 
Section 195.1(a)(4)(ii) states that part 195 applies to a ``regulated 
rural gathering line as provided in Sec.  195.11.'' PHMSA published a 
final rule on June 3, 2008 (73 FR 31634), that prescribed certain 
safety requirements for regulated rural gathering lines (i.e., the 
filing of accident, safety-related condition, and annual reports; 
establishing the MOP in accordance with Sec.  195.406; installing line 
markers; and establishing programs for public awareness, damage 
prevention, corrosion control, and operator qualification of 
personnel).
    The June 2008 final rule did not establish safety standards for all 
rural hazardous liquid gathering lines. Some of those lines cannot be 
regulated by statute (i.e., 49 U.S.C. 60101(b)(2)(B) states that ``the 
definition of ``regulated gathering line'' for hazardous liquid may not 
include a crude oil gathering line that has a nominal diameter of not 
more than 6 inches, is operated at low pressure, and is in a rural area 
that is not unusually sensitive to environmental damage''), and 
Congress did not remove this exemption in the 2011 Pipeline Safety Act.
    PHMSA is currently statutorily limited to regulating gathering 
lines in HCAs and ``regulated rural gathering lines,'' which are 
defined in Sec.  195.11 to mean onshore gathering lines in a rural area 
that meet certain criteria (i.e., has a nominal diameter from 6\5/8\ 
in. (168 mm) to 8\5/8\ in. (219.1 mm), is in or within \1/4\ mile of an 
unusually sensitive area as defined in Sec.  195.6, and operates at a 
maximum pressure established under Sec.  195.406). This limitation 
leaves gaps in the regulation of rural gathering lines not classified 
as regulated rural gathering lines.
    Further, PHMSA currently collects no data on unregulated gathering 
lines. This lack of data prevents PHMSA from being able to determine 
whether current regulations should be applied to currently unregulated 
gathering lines. Therefore, in this final rule, PHMSA is requiring 
reporting on all hazardous liquid gathering lines and will consider, 
based on the nature of the data gathered, the appropriateness of 
additional regulatory requirements, if any, for hazardous liquid 
gathering lines in the future.
    The final rule, however, does not address or require data 
collection for transportation-related flow lines until further study 
and cost analyses can be conducted. PHMSA notes that, per Section 12 of 
the 2011 Pipeline Safety Act, Congress has provided PHMSA with the 
authority to collect data on pipelines transporting oil off the grounds 
of the well where it originated and across areas not owned by the 
producer, regardless of the extent to which the oil has been processed, 
if at all. Aside from this rulemaking, PHMSA may consider collecting 
these data in the future. As discussed above, any decision PHMSA makes 
to expand its oversight of gathering lines beyond what is currently 
regulated will be driven by risk assessment and analysis based on 
evaluations of incident and accident data, data related to 
infrastructure, and further technological advancements such as the 
unconventional production practices used in shale formations.

(2) Require Inspections of Pipelines in Areas Affected by Extreme 
Weather and Natural Disasters

    Extreme weather has been a contributing factor in several pipeline 
failures. For example, in 1994, flooding in Texas led to river scour 
and ground movement that caused the failure of eight pipelines and the 
release of more than 35,000 barrels of hazardous liquids into the San 
Jacinto River. Some of that released product also ignited, causing 
minor burns and other injuries to nearly 550 people according to the 
NTSB. In July 2011, a pipeline failure associated with river bottom 
scour occurred near Laurel, MT, causing the release of an estimated 
1,000 barrels of crude oil into the Yellowstone River. That area had 
experienced extensive flooding due to warm weather causing the rapid 
melting of large snowpack levels in the weeks leading up to the 
failure. The operator estimated the cleanup costs at approximately $135 
million. In January 2015, another pipeline failure caused by river 
bottom scour again occurred on the Yellowstone River, spilling 
approximately 758 barrels of crude oil into the river, causing the 
shutdown of nearby drinking-water intakes.\31\ Additionally, on October 
21, 2016, extreme localized flooding, soil erosion, and ground movement 
caused a release of over 1,238 barrels of gasoline into the Loyalsock 
Creek in Lycoming County, PA. Further, on March 20, 2018, heavy rain 
caused a pipeline to rupture and release 1,400 barrels of diesel fuel 
into Big Creek at Solitude, IN. Specifically, a girth weld on the 
pipeline ruptured due to land slippage caused by the saturated soil.
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    \31\ http://deq.mt.gov/Portals/112/DEQAdmin/DIR/Documents/Bridger%20Consent%20Order/Final%20Bridger%20Consent%20Order.pdf?ver=2017-02-09-121902-843.
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    Weather events and natural disasters that can cause river scour, 
soil subsidence or ground movement may subject pipelines to additional 
external loads, which could cause a pipeline to fail. These conditions 
can pose a threat to the integrity of pipeline facilities if those 
threats are not promptly identified and mitigated. While the existing 
regulations provide for design standards that consider the load that 
may be imposed by geological forces, events like the ones described 
above can quickly impact the safe operation of a pipeline and have 
severe consequences if not mitigated and remediated as quickly as 
possible.
    PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to 
communicate the potential for damage to pipeline facilities caused by 
severe flooding, including actions that operators should consider 
taking to ensure the integrity of pipelines in the event of flooding, 
river scour, river channel migration, and earth movement.\32\ As PHMSA 
has noted in a series of Advisory Bulletins, hurricanes are also 
capable of causing extensive damage to both offshore and inland 
pipelines (e.g., Hurricane Ivan, September 23, 2004 (69 FR 57135); 
Hurricane Katrina, September 7, 2005

[[Page 52269]]

(70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)).
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    \32\ ``Pipeline Safety: Potential for Damage to Pipeline 
Facilities Caused by Flooding, River Scour, and River Channel 
Migration,'' April 9, 2015, 80 FR 19114; and January 19, 2016, 81 FR 
2943. See also ``Pipeline Safety: Potential for Damage to Pipeline 
Facilities Caused by Earth Movement and Other Geological Hazards,'' 
May 2, 2019, 84 FR 18919.
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    These events demonstrate the importance of working to ensure that 
our Nation's waterways and the public are adequately protected from 
pipeline risks in the event of a natural disaster or extreme weather. 
PHMSA is aware that many operators perform inspections following such 
events; however, because it is not a requirement, some operators do 
not. Therefore, PHMSA is amending the PSR to require that operators 
commence inspection of their potentially affected assets within 72 
hours after the cessation of an extreme weather event such as a 
hurricane, flood, landslide, earthquake, or other natural disaster that 
has the likelihood to damage infrastructure. PHMSA would not expect 
operators to comply with these provisions for weather events when, 
considering the physical characteristics, operating conditions, 
location, and prior history of the affected system, the event would not 
have a likelihood of damage to the pipeline. For example, extreme 
weather events would not include rain events that do not exceed the 
high-water banks of the rivers, streams or beaches in proximity to the 
pipeline; rain events that do not result in a landslide in the area of 
the pipeline; storms that do not produce winds at tropical storm or 
hurricane level velocities; or earthquakes that do not cause soil 
movement in the area of the pipeline.
    Under this requirement, an operator must inspect all potentially 
affected pipeline facilities following these types of events to detect 
conditions that could adversely affect the safe operation of the 
pipeline. The operator must consider the nature of the event and the 
physical characteristics, operating conditions, location, and prior 
history of the affected pipeline in determining whether the event 
necessitates an inspection as well as the appropriate method for 
performing the inspection. If the event creates a likelihood that there 
is damage to pipeline infrastructure, the operator must commence an 
inspection within 72 hours after the cessation of the event, defined as 
the point in time when the area can be safely accessed by personnel and 
equipment, including availability of personnel and equipment, required 
to perform the inspection. PHMSA has found that 72 hours is reasonable 
and achievable in most cases based on prior observations of extreme 
events. If an operator finds an adverse condition, the operator must 
take appropriate remedial action to ensure the safe operation of a 
pipeline based on the information obtained from the inspection. Such 
actions might include, but are not limited to:
     Reducing the operating pressure or shutting down the 
pipeline;
     Isolating pipelines in affected areas and performing 
``stand up'' leak tests;
     Modifying, repairing, or replacing any damaged pipeline 
facilities;
     Preventing, mitigating, or eliminating any unsafe 
conditions in the pipeline rights-of-way;
     Performing additional patrols, depth of cover surveys, ILI 
or hydrostatic tests, or other inspections to confirm the condition of 
the pipeline and identify any imminent threats to the pipeline;
     Implementing emergency response activities with Federal, 
State, or local personnel; and
     Notifying affected communities of the steps that can be 
taken to ensure public safety.
    This requirement is based on the experience of PHMSA and is 
expected to increase the likelihood that operators will find and 
respond to safety conditions more quickly.
(3) Require Assessments of Pipelines That Are Not Already Covered Under 
the IM Program Requirements at Least Once Every 10 Years
    PHMSA is requiring that operators periodically assess onshore, 
piggable, hazardous liquid pipeline segments in non-HCAs. PHMSA has 
determined that expanding assessment requirements to these non-HCA 
pipeline segments will provide operators with valuable information they 
may not have collected if regulations were not in place. Such a 
requirement works to ensure prompt detection and remediation of 
corrosion and other deformation anomalies across the Nation, not just 
in populated or environmentally sensitive areas as defined by Federal 
regulations. There is still considerable consequence risk--regarding 
personal safety, environmental damage, and economic impact--of a spill 
in less-populated areas, into waterways not designated as 
``commercially navigable,'' recreational areas, commercial fishing 
areas, and agriculturally productive areas that do not meet the 
definition of an HCA.
    In this rulemaking, Sec.  195.416 requires operators to assess 
onshore, piggable, non-HCA, hazardous liquid pipeline segments at least 
once every 10 years, which allows operators to prioritize assessments 
in HCAs over assessments in non-HCAs (the assessment period is 5 years 
for hazardous liquid pipeline segments that are in or can otherwise 
affect an HCA). The individuals who review the results of these 
assessments will need to be qualified by knowledge, training, and 
experience and will be required to consider any uncertainty in the 
results obtained, including ILI tool tolerance, when determining 
whether any conditions could adversely affect the safe operation of a 
pipeline. Such determinations will have to be made promptly, but no 
later than 180 days after an inspection, unless the operator 
demonstrates that the 180-day deadline is impracticable.
    Operators are required to comply with the other provisions in part 
195 in implementing the requirements in Sec.  195.416. That includes 
having appropriate provisions for performing these periodic assessments 
and any resulting repairs in an operator's procedural manual (see Sec.  
195.402); adhering to the recordkeeping provisions for inspections, 
tests, and repairs (see Sec.  195.404); and taking appropriate remedial 
action under Sec.  195.401(b)(1), as discussed below.
    Such requirements will help ensure operators obtain information 
necessary for the detection and remediation of corrosion and other 
deformation anomalies in all locations, not just HCAs. Of the many 
assessment methods, PHMSA has found that ILI in many cases is the most 
efficient and effective. Operators can perform ILIs while pipelines are 
in service without any interruption of product flow. Further, ILIs are 
non-destructive and can provide information beyond direct assessments, 
which can only tell whether there is exterior coating damage or 
corrosion, and hydrotests, which are essentially ``pass'' or ``fail.'' 
ILI tools, which are constantly improving, can provide accurate 
information on internal corrosion, external corrosion, cracks, and 
gouges. Additionally, there is robust guidance and documentation for 
the use of ILI; API and the National Association of Corrosion Engineers 
(NACE) have developed standards for ILIs that provide guidelines on 
appropriate tool selection, assessment procedures, and the 
qualification of personnel conducting assessments.
    Currently, operators said they are performing ILI assessments on a 
large portion of both HCA and non-HCA pipeline mileage, even though no 
regulation requires them to assess mileage outside of HCAs. Reported 
repairs in non-HCA segments reflect this indication. PHMSA wants to 
best ensure that current assessment rates continue and expand to those 
areas not voluntarily assessed. PHMSA has determined that by adopting 
these amendments to the existing pipeline safety regulations, data 
collection will continue to improve across the entire pipeline system, 
and anomalies that

[[Page 52270]]

may have previously gone undetected in non-HCAs will be detected and 
repaired in a more consistent manner.
(4) Expand the Use of Leak Detection Systems for Certain Hazardous 
Liquid Pipelines
    With respect to new hazardous liquid pipelines, PHMSA is amending 
Sec.  195.134 to require that all new covered pipelines, in both HCAs 
and non-HCAs, have leak detection systems within 1 year after this 
final rule is published in the Federal Register, and all covered 
pipelines constructed prior to the rule's publication have leak 
detection systems within 5 years after this rule is published. Recent 
pipeline accidents, including related failures that occurred in 2010 on 
a crude oil pipeline in Salt Lake City, UT; a failure of another crude 
oil pipeline in Santa Barbara, CA, in 2015; a crude oil release in 
Belfield, ND, in 2016; and the failure of refined products lines in 
Dono Ana County, NM, in 2018, corroborate the significance of having an 
adequate means for identifying leaks in all locations along the 
pipeline right-of-way. PHMSA, aware of the significance of leak 
detection, held a 2-day workshop in Rockville, MD, on March 27-28 of 
2012.\33\ These workshops sought comment from the public concerning 
many of the issues raised in the 2010 ANPRM, including leak detection 
expansion. Both workshops were well attended, and PHMSA received 
valuable input from stakeholders on the technical gaps and challenges 
for future research and ways to leverage resources to achieve common 
objectives and reduce duplication of research programs. Participants 
also discussed the development of leak detection for all pipeline types 
and the capabilities and limitations of current leak detection 
technologies.
---------------------------------------------------------------------------

    \33\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=75.
---------------------------------------------------------------------------

    With respect to existing pipelines, part 195 currently contains 
mandatory leak detection requirements for only those hazardous liquid 
pipelines that could affect an HCA. Congress included additional 
requirements for leak detection systems in section 8 of the 2011 
Pipeline Safety Act. That legislation requires the Secretary to submit 
a report to Congress, within 1 year of the enactment date, on the use 
of leak detection systems, including an analysis of the technical 
limitations and the practicability, safety benefits, and adverse 
consequences of establishing additional standards for the use of those 
systems. Congress authorized the issuance of regulations for leak 
detection if warranted by the findings of the report.
    PHMSA publicly provided the results of the 2012 Kiefner and 
Associates study on leak detection systems in the pipeline industry, 
including the current state of technology. The study found that most 
leak detection technologies can be retrofitted to existing pipelines, 
though many operators ``fear investing in leak detection systems, with 
potentially little benefit to show from them and no way to truly 
measure success in a standardized way,'' resulting in leak detection 
being implemented ``cautiously, and incrementally, on measurement and 
other systems that are already in place.'' \34\
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    \34\ Kiefner and Associates, Inc., ``Final Report on Leak 
Detection Study-DTPH56-11-D-000001,'' December 10, 2012; http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Press%20Release%20Files/Leak%20Detection%20Study.pdf.
---------------------------------------------------------------------------

    Based on information available to PHMSA, including post-accident 
reviews and the Kiefner Report, the need to expand the use of leak 
detection systems and strengthen the current leak detection 
requirements is clear. A robust leak detection system is extremely 
important to hazardous liquid operators because it triggers all other 
impact mitigation measures that an operator should plan for, including 
safe flow shutdown, spill containment, cleanup, and remediation. In 
this final rule, PHMSA is modifying Sec.  195.444 to require a means 
for detecting leaks on all portions of a hazardous liquid pipeline 
system, including non-HCA lines, and to require that operators perform 
an evaluation to determine what kinds of systems must be installed to 
adequately protect the public, property, and the environment. The 
factors that must be considered during that evaluation include (but are 
not limited to) the characteristics and history of the affected 
pipeline, the capabilities of available leak detection systems, and the 
location of emergency response personnel. PHMSA is retaining the 
requirements in Sec. Sec.  195.134 and 195.444 that each new 
computational leak detection system comply with the applicable 
requirements in API Recommended Practice 1130.\35\
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    \35\ API RP 1130 focuses on the design, implementation, testing 
and operation of Computational Pipeline Monitoring (CPM) systems 
that use an algorithmic approach to detect hydraulic anomalies in 
pipeline operating parameters for hazardous liquid pipelines.
---------------------------------------------------------------------------

    Given the difficulties identified in the Kiefner study related to 
leak detection performance standards, PHMSA is not making any 
additional changes to the regulations concerning specific leak 
detection system performance criteria requirements at this time. PHMSA 
will be studying this issue further and may make proposals concerning 
this topic in a later rulemaking.
(5) Increase Accommodation of In-Line Inspection Tools
    In this final rule, PHMSA is amending the part 195 regulations to 
require that all hazardous liquid pipelines in HCAs and areas that 
could affect an HCA be made capable of accommodating ILI tools within 
20 years, unless subject to PHMSA approval, the basic construction of a 
pipeline will not accommodate the passage of such a device or the 
operator determines it would abandon the pipeline because of the cost 
of complying with the amendment. Per the petition process at Sec.  
190.9, operators would be required to document these determinations and 
submit the documentation to PHMSA for approval.
    Modern ILI tools can provide a relatively complete examination of 
the entire length of a pipeline, including information about threats 
that other assessment methods cannot always identify. ILI tools also 
provide superior information about incipient flaws (i.e., flaws that 
are not yet a threat to pipeline integrity, but that could become so in 
the future), thereby allowing these conditions to be monitored over 
consecutive inspections and remediated before a pipeline failure 
occurs. Hydrostatic pressure testing, another well-recognized method, 
reveals flaws (such as wall loss and cracking flaws) that cause pipe 
failures at pressures that exceed actual operating conditions, but only 
allows operators to determine whether a required safety margin is met 
(i.e., pass/fail) and does not provide information about the existence 
of anomalies that could deteriorate over time between tests. Similarly, 
external corrosion direct assessment (ECDA) is a form of direct 
assessment that can identify instances where coating damage or 
ineffective coatings may be affecting pipeline integrity, but operators 
must perform additional activities, including follow-up excavations and 
direct examinations, to verify the extent of that threat. ECDA also 
does not provide information about the internal condition of a pipe to 
the extent an ILI tool would.
    The current regulations for the passage of ILI devices in hazardous 
liquid pipelines are prescribed in Sec.  195.120, which require that 
new and replaced pipelines are designed to accommodate ILI tools. The 
basis for these requirements is a 1988 law that addressed the 
Secretary's authority with regard to requiring the accommodation

[[Page 52271]]

of ILI tools. This law required the Secretary to establish minimum 
Federal safety standards for the use of ILI tools, but only in newly 
constructed and replaced hazardous liquid pipelines (Pub. L. 100-561).
    As the Research and Special Programs Administration (RSPA; a 
predecessor agency of PHMSA), explained in the final rule published on 
April 12, 1994 (59 FR 17275), that promulgated Sec.  195.120, ``the 
clear intent of th[at] congressional mandate [wa]s to improve an 
existing pipeline's piggability,'' and to ``require the gradual 
elimination of restrictions in existing hazardous liquid and carbon 
dioxide lines in a manner that will eventually make the lines 
piggable.'' RSPA also noted that Congress amended the 1988 law in the 
Pipeline Safety Act of 1992 (Pub. L. 102-508) to require the periodic 
internal inspection of hazardous liquid pipelines, including with ILI 
tools in appropriate circumstances. In 1996, Congress passed another 
law further expanding the Secretary's authority to require pipeline 
operators to have systems that can accommodate ILI tools. In 
particular, Congress provided additional authority for the Secretary to 
require the modification of existing pipelines whose basic construction 
would accommodate an ILI tool to accommodate such a tool and permit 
internal inspection (Pub. L. 104-304). RSPA established requirements 
for the use of ILI tools in pipelines that could affect HCAs in a final 
rule published on December 1, 2000 (65 FR 75378).
    Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the 
requirements for the passage of ILI tools to be extended to existing 
hazardous liquid pipeline facilities, provided the basic construction 
of those facilities can be modified to permit the use of smart pigs. 
The current requirements apply only to new hazardous liquid pipelines 
and to line sections where the line pipe, valves, fittings, or other 
components are replaced. Exceptions are also provided for certain kinds 
of pipeline facilities, including manifolds, piping at stations and 
storage facilities, piping of a size that cannot be inspected with a 
commercially available ILI tool, and smaller-diameter offshore 
pipelines.
    In this final rule, PHMSA is taking steps to further facilitate the 
gradual elimination of pipelines that are not capable of accommodating 
smart pigs in accordance with the authority provided in section 
60102(f)(1)(B). PHMSA is limiting the circumstances where a pipeline 
can be constructed without being able to accommodate a smart pig. Under 
the current regulation, an operator can petition the PHMSA 
Administrator for such an allowance for reasons of impracticability, 
emergencies, construction time constraints, costs, and other unforeseen 
construction problems. PHMSA believes that an exception should still be 
available for emergencies and where the basic existing construction of 
a pipeline makes that accommodation impracticable.
    Regulations already require that new and replaced pipelines 
accommodate ILI tools, and many of the pipelines covered by this new 
rule will need to be replaced and therefore will accommodate ILI tools 
before the end of the 20-year implementation period. Providing industry 
with sufficient time to implement this provision allows the industry to 
prioritize retrofits and replacements based on age or other factors; it 
also reduces the mileage of pipeline potentially needing to be replaced 
before it has reached the limit of its operational life. PHMSA 
determined that the 20-year timeline strikes the appropriate balance 
between the need for upgrades with the operational challenges of making 
these changes.
(6) Clarify Other Requirements
    In this final rule, PHMSA is also making several other clarifying 
changes to the regulations that are intended to improve compliance and 
enforcement. First, PHMSA is proposing to revise paragraph (b)(1) of 
Sec.  195.452 to better harmonize this section with other parts of the 
current regulations. Currently, Sec.  195.452(b)(2) requires that 
segments of new pipelines that could affect HCAs be identified before 
the pipeline begins operations, and Sec.  195.452(d)(1) requires that 
baseline assessments for covered segments of new pipelines be completed 
by the date the pipeline begins operation. However, Sec.  195.452(b)(1) 
does not require an operator to draft its IM program for a new pipeline 
until 1 year after the pipeline begins operation. These provisions are 
inconsistent, as the identification of could-affect segments and 
performance of baseline assessments are elements of the written IM 
program. PHMSA is amending the table in (b)(1) to resolve this issue by 
eliminating the 1-year compliance deadline for Category 3 pipelines. An 
operator of a new pipeline is required to develop its written IM 
program before the pipeline begins operation--there is no burden 
associated with this amendment because operators already were required 
to report to DOT prior to construction.
    Second, as mentioned in the non-HCA assessment section, operators 
of both HCA lines and non-HCA lines will have equal requirements for 
the ``discovery'' of conditions, which occurs when an operator has 
adequate information about a condition to determine that it presents a 
potential threat to the integrity of the pipeline. An operator must 
promptly, but no later than 180 days after an integrity assessment, 
obtain sufficient information about a condition to make that 
determination, unless the operator can demonstrate that the 180-day 
period is impracticable. This could include demonstrating why such 
information would not be available prior to that date. If an operator 
believes that unique circumstances exist in a particular case that make 
the 180-day period impracticable, the operator must submit a 
notification to PHMSA and provide an expected date when adequate 
information will become available. The submission of such a 
notification, by itself, will not affect compliance determinations on 
whether the 180-day requirement was met. PHMSA is thereby amending the 
existing ``discovery of condition'' language at Sec.  195.452(h)(2) in 
the pipeline safety regulations to reflect these changes.
    A decade's worth of IM inspection experience has shown that many 
operators are performing inadequate information analyses (i.e., they 
are collecting information but are not affording it sufficient 
consideration, or they are not promptly evaluating the information they 
have gathered following events that have increased risk, such as 
historic weather events). Ongoing data integration is one of the most 
important aspects of the IM program, and operators must account for 
interactions between threats or conditions affecting the pipeline when 
setting priorities for dealing with identified issues. For example, 
evidence of potential corrosion in an area with foreign pipeline 
crossings,\36\ nearby current interference from power lines and 
electrically powered transport systems, evidence of land movement or 
waterway channel changes that may impact pipeline integrity, and recent 
aerial patrol indications of excavation activity could indicate a 
priority for operators to reassess risk and make timely changes to 
their IM program to reduce that risk. Consideration of each of these 
factors individually would not necessarily reveal any need for priority 
attention. PHMSA is concerned that a major benefit to pipeline safety 
intended in the IM rule is not being realized

[[Page 52272]]

because of inadequate information analyses.
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    \36\ Foreign pipelines can include other hazardous liquid, 
natural gas, water, sewer, or drainage pipelines.
---------------------------------------------------------------------------

    For this reason, PHMSA is adding specificity to paragraph (g) by 
establishing several pipeline attributes that must be included in these 
analyses and requiring explicitly that operators integrate analyzed 
information. PHMSA is also requiring operators to consider explicitly 
any spatial relationships among anomalous information. PHMSA supports 
the use of computer-based geographic information systems (GIS) to 
record this information. GIS systems can be beneficial in identifying 
spatial relationships, but analysis is required to identify where these 
relationships could result in situations adverse to pipeline integrity.
    Second, PHMSA is requiring operators to verify their pipeline 
segment identification (as HCAs or otherwise) annually by determining 
whether factors considered in their analysis have changed. Section 
195.452(b) currently requires that operators identify each segment of 
their pipeline that could affect an HCA in the event of a release, but 
there is no explicit requirement that operators assure that their 
identification of covered segments remains current. As time goes by, 
the likelihood increases that factors considered in the original 
identification of covered segments may have changed. Construction 
activities or erosion near the pipeline could change local topography 
in a way that could cause product released in an accident to travel 
farther than initially analyzed. Changes in agricultural land use could 
also affect an operator's analysis of the distance released product 
could be expected to travel. Changes in the deployment of emergency 
response personnel could increase the time required to respond to a 
release and result in a release affecting a larger area if the original 
segment identification relied on emergency response in limiting the 
transport of released product. Therefore, PHMSA has determined that 
operators should periodically re-visit their initial analyses to 
determine whether they need updating; operators might identify new HCAs 
in subsequent analyses.
    The change that PHMSA is adopting does not automatically require 
operators to re-perform their segment analyses. Rather, it requires 
operators to first identify the factors considered in their original 
analyses, determine whether those factors have changed, and consider 
whether any such change would likely affect the results of the original 
segment identification. If so, the operator is required to perform a 
new segment analysis to validate or change the endpoints of the 
segments affected by the change.
    Further, Section 29 of the 2011 Pipeline Safety Act states that 
``[i]n identifying and evaluating all potential threats to each 
pipeline segment pursuant to parts 192 and 195 of title 49, Code of 
Federal Regulations, an operator of a pipeline facility shall consider 
the seismicity of the area.'' While seismicity is already mentioned at 
several points in the IM program guidance provided in Appendix C of 49 
CFR part 195, PHMSA is amending the PSR to further comply with 
Congress's directive by including an explicit reference to seismicity 
in the list of risk factors that must be considered in establishing 
assessment schedules (Sec.  195.452(e)), performing information 
analyses (Sec.  195.452(g)), and implementing preventive and mitigative 
measures (Sec.  195.452(i)) under the IM requirements.
    Finally, the PIPES Act of 2016 contained two sections PHMSA 
identified as self-executing and that PHMSA could incorporate into the 
PSR without notice of public comment or previous proposed rulemaking. 
Section 14 of the PIPES Act of 2016 requires operators of hazardous 
liquid pipeline facilities to provide safety data sheets to the 
designated Federal On-Scene Coordinator and appropriate State and local 
emergency responders within 6 hours of a telephonic or electronic 
notice of the accident to the National Response Center. Section 25 of 
the PIPES Act of 2016 requires operators of underwater hazardous liquid 
pipeline facilities in HCAs that are not offshore pipeline facilities 
and that any portion of which are located at depths greater than 150 
feet below the surface of the water to complete ILI assessments 
appropriate to the integrity threats specific to those pipelines no 
less frequently than once every 12 months. Furthermore, section 25 of 
the PIPES Act of 2016 requires that operators use pipeline route 
surveys, depth of cover surveys, pressure tests, ECDAs, or other 
technology that the operator demonstrates can further the understanding 
of the condition of the pipeline facility, as necessary to assess the 
integrity of those pipelines on a schedule based on the risk that the 
pipeline facility poses to the HCA in which the facility is located. 
PHMSA is amending the PSR by codifying the statutory language of these 
provisions.

III. Liquid Pipeline Advisory Committee Recommendations

    The Liquid Pipeline Advisory Committee (LPAC) is a statutorily 
mandated advisory committee that advises PHMSA on proposed safety 
standards, risk assessments, and safety policies for hazardous liquid 
pipelines. The Pipeline Advisory Committees (PAC) were established 
under the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 
1-16) and the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). 
Each committee consists of 15 members, with membership divided among 
the Federal and State agencies, the regulated industry, and the 
public.\37\ The PACs advise PHMSA on the technical feasibility, 
practicability, and cost-effectiveness of each proposed pipeline safety 
standard.
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    \37\ Members from the general public include two members who 
have education, background, or experience in environmental 
protection or public safety. At least one of the five members must 
have education, background, or experience in risk assessment and 
cost-benefit analysis. No public member can have a significant 
interest in the pipeline, petroleum, or gas industry. At least one 
of the public members must have no financial interests in the 
pipeline, petroleum, or natural gas industries. See section 12(d), 
``Liquid Pipeline Advisory Committee Charter--October 2018 to 
October 2020,'' https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/standards-rulemaking/pipeline/4396/lpac-charter-final-102418.pdf.
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    On February 1, 2016, the LPAC met at the Hilton Arlington in 
Arlington, VA, to discuss this rulemaking. During the meeting, the LPAC 
considered the specific regulatory proposals of the NPRM and discussed 
various comments to the NPRM proposed by the pipeline industry, public 
interest groups, and government entities. To assist the LPAC in their 
deliberations, PHMSA presented a description and summary of the eight 
major issues in the NPRM and the comments received on those issues, as 
well as some sample regulatory text changes to foster discussion.
    During the meeting, eight votes were taken: One vote on each major 
topic of the NPRM. For each major topic of the rule, the LPAC came to a 
consensus decision that the provisions of the rulemaking would be 
technically feasible, reasonable, cost-effective, and practicable, 
provided PHMSA made certain changes. The order the topics were 
discussed in, the changes the committee agreed upon, and the 
corresponding vote counts were as follows:
    Gravity lines: In the NPRM, PHMSA proposed to subject gravity lines 
to reporting requirements for data gathering purposes, as there are 
currently no regulatory requirements for these lines and little data 
for potential regulatory decision-making purposes. The LPAC voted 9-1 
that the NPRM, with respect to gravity lines, as published in the 
Federal Register, and the draft regulatory evaluation were technically 
feasible, reasonable, cost-

[[Page 52273]]

effective, and practicable, if PHMSA made the following changes: Modify 
(shorten) the reporting form, require no National Pipeline Mapping 
System (NPMS) submissions, provide reporting exceptions for lower-risk 
pipelines (for example, intra-plant lines), allow a 1-year 
implementation period for annual reporting, and allow a 6-month 
implementation period for accident reporting.
    The LPAC agreed that PHMSA should modify the reporting forms to 
gather only the data necessary for PHMSA to determine whether these 
lines need to be regulated in the future. LPAC members representing the 
pipeline industry requested that PHMSA consider reporting exceptions 
for lower-risk pipelines, such as intra-plant gravity lines. The same 
members also requested that any reporting requirements for gravity 
lines not include NPMS submissions, asserting that incorporating that 
data into a mapping system would be costly compared to the amount of 
risk these lines pose. LPAC members representing the public did not 
support these recommendations. They noted that as gravity line mileage 
is already limited, and the reporting requirement is only being used to 
gather data, excepting a subset of this limited mileage from reporting 
requirements would be counter-productive. Further, the public members 
strongly suggested that NPMS submissions be included for gravity lines, 
as location could be an important data point PHMSA could collect.
    Gathering lines: In the NPRM, PHMSA proposed to collect information 
on all gathering lines and subject regulated gathering lines to 
periodic assessment and leak detection requirements. Much of the LPAC's 
discussion for gathering lines mirrored the topics discussed regarding 
gravity lines. During the discussion, PHMSA noted that under 49 U.S.C. 
60132, only transmission-pipeline operators are required to submit 
mapping data for use in the NPMS. As a result, the LPAC removed 
language concerning NPMS submissions by gathering line operators. 
Ultimately, the committee voted 10-0 that the NPRM regarding gathering 
lines, as published in the Federal Register, and the draft regulatory 
evaluation are technically feasible, reasonable, cost effective, and 
practicable if PHMSA made the following changes: modify (shorten) the 
reporting form, allow a 1-year implementation period for annual 
reporting, and allow a 6-month implementation period for accident 
reporting.
    Leak detection: In the NPRM, PHMSA proposed that all hazardous 
liquid pipelines transporting liquid in single phase (without gas in 
the liquid) include a leak detection system and have it operate and 
maintained per specified standards. Many commenters noted that there 
was no implementation period for PHMSA's proposed leak detection 
requirements. The LPAC proposed a 5-year implementation period for leak 
detection systems on existing lines and a 1-year implementation period 
for leak detection systems on new lines. The LPAC also recommended 
PHMSA not apply leak detection requirements to offshore gathering lines 
due to various technical challenges associated with flow monitoring and 
leak detecting. The LPAC voted unanimously that the NPRM, regarding 
leak detection, as published in the Federal Register, and the draft 
regulatory evaluation are technically feasible, reasonable, cost 
effective, and practicable if PHMSA made the following changes: Allow a 
5-year implementation period for existing pipelines, allow a 1-year 
implementation period for new pipelines, and exempt offshore gathering 
lines from the leak detection requirements.
    Clarifying other requirements: In the NPRM, PHMSA proposed to 
revise the IM requirements to specify additional pipeline attributes 
for operators to analyze when evaluating the integrity of pipelines in 
HCAs; to require the integration of all sources of information, 
including spatial relationships, when determining pipeline integrity; 
to require operators have a written IM plan prior to a specific 
pipeline's operation; and to require annual HCA segment identification 
and verification. During the meeting, the LPAC primarily discussed 
whether there should be a timeframe for implementing the specific data 
attributes and integrating all sources of information when determining 
pipeline integrity. Committee members representing the public argued 
that, because these provisions were clarifications of existing 
requirements, operators should have already been performing many of 
these actions, and an extended implementation period would not make 
sense. Several members who represented the public pushed for a 1-year 
implementation period. LPAC members representing the industry noted 
that developing data integration systems to a level that PHMSA would 
like could be expensive and time-consuming, possibly taking several 
years. Further, LPAC members representing industry noted that while a 
lot of data integration is already occurring in operators' IM programs, 
it could take some operators an extended period to adjust their 
software to incorporate all the items in PHMSA's proposed list. LPAC 
members representing industry proposed PHMSA allow operators a 3-year 
deadline from the rule's issuance to fully implement the proposed list 
of attributes. Ultimately, the LPAC voted 7-3 that the NPRM, regarding 
the data integration requirements, as published in the Federal 
Register, and the draft regulatory evaluation are technically feasible, 
reasonable, cost-effective, and practicable if operators begin 
implementing the requirements upon the rule's issuance with a deadline 
of 3 years for full implementation.
    Inspections following extreme weather events: In the NPRM, PHMSA 
proposed requiring operators to perform inspections of pipelines that 
may have been affected by natural disasters or extreme weather events 
within 72 hours after the cessation of the event to better ensure that 
no conditions exist that could adversely affect the safe operation of 
that pipeline. The LPAC voted unanimously that the NPRM, as it relates 
to inspections following extreme weather events, as published in the 
Federal Register, and the draft regulatory evaluation are technically 
feasible, reasonable, cost-effective, and practicable, if PHMSA 
included the term ``landslide'' as a specific extreme weather event and 
qualify the term ``other similar events'' as it pertains to triggering 
the requirements of performing an inspection by tying the term to those 
events ``that the operator determines to have a significant likelihood 
of damage to infrastructure.'' Further, the LPAC recommended PHMSA 
clarify that the purpose of the inspection is to ``detect conditions 
that could adversely affect the safe operation of the pipeline'' and 
not ``ensure that no conditions exist that could adversely affect the 
safe operation of the pipeline.'' The LPAC also recommended PHMSA 
clarify that the inspection per these requirements would be an initial 
inspection, conducted within 72 hours of the area being safely 
accessible by personnel and equipment, to determine if any damage has 
occurred and whether additional assessments are necessary.
    Periodic assessments in non-HCAs: In the NPRM, PHMSA proposed to 
require operators to assess non-HCA pipelines at least once every 10 
years using ILI or other equivalent methods. The LPAC agreed on this 
requirement and wanted to ensure it was not more restrictive than the 
requirement for assessing lines

[[Page 52274]]

in HCAs. The LPAC voted unanimously that, regarding the provisions of 
the NPRM related to periodic assessments, the NPRM, as published in the 
Federal Register, and the draft regulatory evaluation are technically 
feasible, reasonable, cost-effective, and practicable if PHMSA ensured 
that the periodic assessment requirement applies to regulated pipelines 
that are not currently subject to the IM requirements at Sec.  195.452, 
and made the methods operators use to assess non-HCA pipelines 
consistent with the methods operators use to assess HCA pipelines and 
allow operators to choose the appropriate tool for the appropriate 
threat.
    Making all pipelines in HCAs able to accommodate ILI tools: In the 
NPRM, PHMSA proposed to require all pipelines in HCAs be capable of 
accommodating ILI tools within 20 years. The LPAC voted 9-1 that, 
regarding the provision of the rule requiring the use of ILI tools in 
all HCAs, the NPRM, as published in the Federal Register, and the draft 
regulatory evaluation are technically feasible, reasonable, cost-
effective, and practicable provided PHMSA insert a phrase stating that 
an operator can also file a petition if it determines it would abandon 
or otherwise shut down a pipeline because of the compliance cost of the 
provision.
    Repair criteria: In the NPRM, PHMSA proposed to make various 
changes to the existing repair criteria to reflect an improved 
prioritization of repairing abnormal pipeline conditions. The LPAC 
voted unanimously that, with regard to repair criteria for both HCA and 
non-HCA pipeline segments, the NPRM, as published in the Federal 
Register, and the draft regulatory evaluation are technically feasible, 
reasonable, cost-effective, and practicable if PHMSA considers allowing 
recognized engineering analyses to determine whether applicable dents 
and cracks are non-injurious and need no further investigation, and 
gives ``full and equal consideration to the industry comments that were 
discussed [at the meeting].'' \38\ Those hazardous liquid industry 
comments provided at the LPAC meeting for PHMSA to consider were as 
follows:
---------------------------------------------------------------------------

    \38\ At the Advisory Committee meeting, member Craig Pierson, 
representing the pipeline industry, submitted for the members' 
consideration a written recommendation regarding repair criteria 
anomalies.
---------------------------------------------------------------------------

    Repair Criteria for both HCA and non-HCA pipeline segments:
    1. Regarding ``Immediate'' conditions:
    a. Include crack anomalies greater than 70 percent of wall 
thickness or the tool's maximum measurable depth if it is less than 70 
percent;
    b. Remove specific references to ``any indication'' of significant 
stress corrosion cracking (SCC) and selective seam weld corrosion 
(SSWC).
    c. Allow for an industry recognized engineering analysis to 
determine those dents that are non-injurious and require no further 
investigation; and
    d. Instead of addressing cracks and SSWC specifically, expand the 
various accepted failure models that identify an anomaly that does not 
have the remaining strength to exceed 1.1 times the MOP at the location 
of the anomaly, which should also include injurious cracks and SSWC.
    2. Regarding 270-day conditions for HCAs and 18-month conditions 
for non-HCAs:
    a. Revise the existing reference to cracks and include crack 
anomalies greater than 50 percent of wall thickness or the tool's 
maximum measurable depth if it is less than 50 percent;
    b. Allow for an industry recognized engineering analysis to 
determine those dents that are non-injurious and require no further 
investigation; and
    c. To address cracks and SSWC, expand the various accepted failure 
models that identify an anomaly that does not have the remaining 
strength to exceed 1.25 times the MOP at the location of the anomaly.
    3. Add a ``Scheduled condition:''
    a. Anomalies that do not meet the 270-day or the 18-month repair 
criteria but have the possibility to grow before the next segment 
inspection are subject to predictive modeling of remaining strength; 
and
    b. Investigate in the years prior to the next inspection if the 
predicted burst pressure is less than 1.1 times the MOP at the location 
of the anomaly.
    In this final rule, PHMSA considered the recommendations of the 
LPAC and adopted them as PHMSA deemed appropriate. To summarize, the 
major changes PHMSA has made in this rule that deviate from the LPAC 
recommendations are as follows: (1) PHMSA has added an additional 
requirement that operators notify the appropriate PHMSA Region Director 
when they are unable to inspect infrastructure impacted by extreme 
weather within 72 hours; (2) PHMSA has removed the phrase ``other 
similar event'' from the extreme weather inspection requirements; (3) 
PHMSA has changed a word in the regulatory text for non-HCA 
assessments, to provide that operators must assess ``line pipe'' 
(instead of ``pipelines defined under Sec.  195.1'') not subject to the 
IM requirements at Sec.  195.452; (4) PHMSA has restricted the non-HCA 
periodic assessment requirement to onshore, piggable, line pipe only, 
which removed the proposed assessment requirement for covered offshore 
lines and for regulated rural gathering lines; (5) PHMSA has removed 
the leak detection requirement for rural regulated gathering lines at 
Sec.  195.11; and (6) PHMSA declined to move forward with the repair 
criteria and timelines as proposed for both HCAs and non-HCAs and has, 
instead, reverted to the existing non-IM repair language in Sec.  
195.401(b)(1) and the existing IM repair language at Sec.  195.452(h). 
In the comments section, for each major topic of this final rule, PHMSA 
broadly discusses specific amendments proposed during the meeting and 
the corresponding discussion. PHMSA also discusses the instances where 
PHMSA did not adopt the specific recommendations of the LPAC.

IV. Analysis of Comments and PHMSA Response

    On October 13, 2015, PHMSA published an NPRM (80 FR 61609) 
proposing several amendments to 49 CFR part 195. The NPRM proposed 
amendments addressing the following areas:
    (1) Reporting requirements for gravity lines.
    (2) Reporting requirements for gathering lines.
    (3) Inspections of pipelines following extreme weather events.
    (4) Periodic assessments of pipelines not subject to IM.
    (5) Repair criteria.
    (6) Expanded use of leak detection systems.
    (7) Increased use of in-line inspection tools.
    (8) Clarifying other requirements.
    Seventy organizations and individuals submitted comments in 
response to the NPRM, including public representatives, private 
citizens, industry service providers, individual pipeline operators, 
and trade associations representing pipeline operators. Some of the 
comments PHMSA received in response to the NPRM were comments beyond 
the scope or authority of the proposed regulations. The absence of 
amendments in this proceeding involving other pipeline safety issues 
(including several topics listed in the ANPRM) does not mean that PHMSA 
determined additional rules or amendments on other issues are not 
needed. Such issues may be the subject of other existing

[[Page 52275]]

rulemaking proceedings or future rulemaking proceedings.
    The remaining comments reflect a wide variety of views on the 
merits of particular sections of the NPRM. The substantive comments 
received on the NPRM are organized by topic below and are discussed in 
the appropriate section with PHMSA's response and resolution to those 
comments.

A. Reporting Requirements for Gravity Lines

1. PHMSA's Proposal
    Gravity lines, pipelines that carry product by means of gravity, 
are currently exempt from PHMSA regulations. Many gravity lines are 
short and within tank farms or other pipeline facilities; however, some 
gravity lines are longer and can build up large amounts of pressure 
because they traverse areas with significant elevation changes, which 
could have significant consequences in the event of a release.
    For PHMSA to effectively analyze gravity line safety performance 
and risk, PHMSA needs basic data about those pipelines. PHMSA has the 
statutory authority to gather data for all pipelines (49 U.S.C. 
60117(b)), and that authority was not affected by any of the provisions 
in the 2011 Pipeline Safety Act. Accordingly, PHMSA proposed to add 
Sec.  195.1(a)(5) to require that the operators of all gravity lines 
comply with requirements for submitting annual, safety-related 
condition, and incident reports.
2. Summary of Public Comment
    PHMSA received comments from trade organizations, citizen groups, 
and individuals on the scope and format of the reporting requirements. 
To reduce the reporting burden, industry representatives (API-AOPL, the 
GPA Midstream Association (GPA) and Energy Transfer Partners (ETP)) 
recommended that PHMSA create a new abbreviated annual report with 
input from operators to separate the reporting of pipeline data for 
regulated pipelines and those not currently subject to 49 CFR part 195. 
Specifically, API noted that pipelines not currently covered under part 
195 (gravity lines) are not subject to operator qualification, control 
room management, leak detection, and HCA requirements, and therefore 
those areas should be excluded from reporting. The Texas Pipeline 
Association requested that reporting be limited to annual and incident 
reports, a suggestion also supported by the ETP. API-AOPL commented 
that industry experience indicates that the cost and time burdens 
associated with the reporting requirements for gravity lines exceeded 
the cost estimate cited by PHMSA in the NPRM.
    The Environmental Defense Center requested that the reporting 
requirements include the location, operation, condition, and history of 
the pipelines, and multiple citizen groups requested that GIS mapping 
be required for pipelines. In addition to GIS mapping information, the 
Western Organization of Resource Councils and the Alliance for Great 
Lakes et al. recommended that PHMSA also require pipeline operators to 
meet minimum safety standards for all pipelines, a comment echoed by 
numerous other citizen groups and individuals. These commenters also 
requested that inspection reports, notices of violation, and similar 
documents be made readily available to the public.
    Trade organizations made additional comments regarding the 
applicability and implementation timeline for the reporting 
requirements. API-AOPL and other industry representatives requested 
that the data collection be narrowed, such that it would apply only to 
those gravity lines that could present a risk to the public, which: (1) 
Travel outside of facility boundaries for at least 1 mile, (2) operate 
at a specified minimum yield strength level of twenty percent or 
greater, and (3) are not otherwise exempted in Sec.  195.1(b). On this 
same basis, Denbury Resources added a request to exempt CO2 
pipelines. Finally, API-AOPL requested that PHMSA extend the proposed 
implementation period to 1 year after the effective date of the final 
rule.
    During the February 1, 2016, meeting, the LPAC recommended that 
PHMSA modify the NPRM to (1) require reporting from gravity pipeline 
operators using streamlined forms, (2) not require integration of 
gravity lines into NPMS, (3) provide exceptions for lower-risk 
pipelines (e.g., intra-plant lines), and (4) set a 1-year 
implementation period for the annual reporting requirement and a 6-
month implementation period for the accident reporting requirement.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the scope and timing of the requirements for gravity lines. 
After considering these comments and LPAC input, PHMSA is modifying the 
exception for gravity lines at Sec.  195.1 as it pertains to reporting 
requirements. This change will allow PHMSA to require operators of 
gravity lines to report information annually, starting 1 year from the 
rule's effective date, and to report accidents and safety-related 
conditions starting 6 months from the rule's effective date. PHMSA 
considers these deadlines practicable in view of the limited scope of 
the information requested for these lines.
    PHMSA focused collection on those data elements that will enable 
the agency to assess the risk posed by these lines and determine 
whether requirements that are more stringent are warranted in the 
future. To facilitate reporting and address commenters' concerns about 
providing clear instructions on data elements that operators must fill 
out for gravity lines, PHMSA has modified its existing reporting form 
to provide clear instructions, including skip patterns, for relevant 
sections. In response to API's specific suggestions regarding operator 
qualification, control room management, leak detection, and HCA 
reporting, these revisions exempted gravity lines from any fields that 
involve ``Could Affect HCA'' data. This targeting of the information 
collection request will reduce the burden associated with providing the 
information, as was requested by commenters. PHMSA recognizes that 
operators who are not currently submitting data will have to register 
with PHMSA to obtain an Operator Identification Number (OPID) under 
Sec.  195.64, but the associated burden is minimal; PHMSA estimates 
that fewer than 10 operators would need to submit information for 
gravity lines. PHMSA estimates the total reporting burden at 66 hours 
per year, on average.
    During the LPAC meeting, the committee reached consensus on 
requiring gravity line operators to report safety-related conditions. 
These conditions could lead to significant consequences and are 
important data points for PHMSA to determine whether additional gravity 
line regulations may be necessary in the future.
    As explained previously, the purpose of the information collection 
is to support evaluation of the risk posed by gravity lines on the 
public. With this goal in mind, PHMSA is receptive to commenters who 
noted that pipelines located within the confines of a facility or in 
close proximity (within 1 mile) to a facility and do not cross a 
waterway currently used for commercial navigation pose a lower risk to 
the public and the environment. PHMSA has decided to exempt these lines 
from the reporting requirements. The language for this exception is 
similar to the language of an existing exception for low-stress 
pipelines at Sec.  195.1.
    Further safety-related condition reporting exceptions at Sec.  
195.55(b) will help minimize the reporting burdens for

[[Page 52276]]

operators. In the NPRM, PHMSA did not intend to propose requiring 
mapping of gravity lines at this time and therefore is finalizing the 
rule without this requirement. PHMSA understands commenters' concerns 
that gravity line NPMS data submissions could be costly and burdensome. 
However, as PHMSA is not requiring these submissions as a part of this 
final rule's reporting requirements, the cost and burden of these 
submissions were not and should not be considered as a part of the 
cost-benefit analysis. If PHMSA determines, following analysis of the 
data received on gravity lines, that mapping of these lines or 
expanding reporting applicability to lines exempted in this final rule 
would be beneficial to improve public safety or protect the 
environment, it may consider additional requirements in a future 
rulemaking.
    Similarly, PHMSA is not requiring telephonic reporting of accidents 
involving gravity lines at this time but may reassess this requirement 
in a future rulemaking if analyses of the data suggest that doing so 
would enhance prevention, preparedness, and response to hazardous 
liquid releases from gravity lines.
    Comments relating to public reporting and the reporting of specific 
pipeline attributes discussed issues that PHMSA did not propose in the 
NPRM and are therefore out-of-scope and could not be considered for 
this rulemaking. Similarly, comments discussing minimum safety 
standards be applied to gravity lines were also out-of-scope because 
they requested more stringent requirements than what PHMSA proposed in 
the NPRM.

B. Reporting Requirements for Gathering Lines

1. PHMSA's Proposal
    In the NPRM, PHMSA also proposed to extend the reporting 
requirements of 49 CFR part 195 to all hazardous liquid gathering 
lines. Recent data indicates that PHMSA regulates less than 4,000 miles 
of the approximately 30,000 to 40,000 miles of onshore hazardous liquid 
gathering lines in the United States.\39\ That means that about 90 
percent of the onshore gathering line mileage is not currently subject 
to any minimum Federal pipeline safety standards. Congress also ordered 
the review of existing State and Federal regulations for hazardous 
liquid gathering lines in the Pipeline Safety Act of 2011, to prepare a 
report on whether any of the existing exceptions for these lines should 
be modified or repealed, and to determine whether hazardous liquid 
gathering lines located offshore or in the inlets of the Gulf of Mexico 
should be subjected to the same safety standards as all other hazardous 
liquid gathering lines. Based on the study titled ``Review of Existing 
Federal and State Regulations for Gas and Hazardous Liquid Gathering 
Lines'' \40\ that was performed by the Oak Ridge National Laboratory 
and published on May 8, 2015, PHMSA proposed additional regulations to 
help ensure the safety of hazardous liquid gathering lines.
---------------------------------------------------------------------------

    \39\ GAO-12-388: ``Pipeline Safety: Collecting Data and Sharing 
Information on Federally Unregulated Gathering Pipelines Could Help 
Enhance Safety,'' March 2012, pg. 7; http://www.gao.gov/assets/590/589514.pdf.
    \40\ http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/report_to_congress_on_gathering_lines.pdf.
---------------------------------------------------------------------------

    For PHMSA to effectively analyze safety performance and risk of 
gathering lines, we need basic data about those pipelines. PHMSA has 
statutory authority to gather data for all gathering lines (49 U.S.C. 
60117(b)). Accordingly, PHMSA proposed to add Sec.  195.1(a)(5) to 
require that the operators of all gathering lines (whether onshore, 
offshore, regulated, or unregulated) comply with requirements for 
submitting annual, safety-related condition, and incident reports.
2. Summary of Public Comment
    PHMSA received comments on hazardous liquid gathering lines that 
echoed those for gravity lines. Citizen groups and individuals again 
requested that the requirements for these lines include GIS mapping and 
minimum safety standards; that the reporting include location, 
operation, condition, and history; and that inspection reports, notices 
of violation, and similar documents be made available to the public. 
Trade organizations again commented on compliance costs and recommended 
that the reporting requirement be limited to annual and incident 
reports with an abbreviated form, have a phase-in implementation over 1 
year, and exempt lower-risk pipelines. Specifically, API noted again 
that, as rural gathering lines are not subject to operator 
qualification, control room management, leak detection, and HCA 
requirements, those areas should be excluded from reporting.
    Trade organizations also made several additional recommendations 
related to the scope of applicability, the scope of requirements, and 
implementation. The Independent Petroleum Association of America (IPAA) 
commented that PHMSA exceeds its authority in requiring operators of 
gathering lines to submit annual, safety-related condition, and 
incident reports. The GPA and other organizations noted that PHMSA did 
not fully account for the burden increase and cost of the reporting 
requirements for gathering lines in the preliminary RIA. The GPA 
recommended that information requested under Sec.  195.61 and Sec.  
195.64 be excluded from data collection. Numerous trade organizations 
identified accident reporting for these lines as costly and 
duplicative. The Louisiana Mid-Continent Oil and Gas Association 
(LMOGA) commented that most, if not all accident information requested 
for gathering lines is already required to be reported under other 
existing Federal and State regulations, and the GPA recommended that 
information collected through an abbreviated Annual Report could be 
paired with Accident Reporting on Form F 7000-1 (rev 7-2014). LMOGA 
also recommended that mapping of gathering lines not be required 
because of incidental environmental impacts on wetlands, permitting, 
and resource costs for teams to enter wetlands and track these lines.
    The Offshore Operators Committee (OOC) requested that PHMSA make 
clear in the final rule that the agency's intent is not to have the 
proposed reporting requirements apply to gathering lines offshore 
within State waters that are currently not regulated by PHMSA or the 
Bureau of Safety and Environmental Enforcement (BSEE) or to other 
gathering lines that are regulated by BSEE.
    Finally, commenters asked for implementation periods that ranged 
from 1 year (API-AOPL) to 10 years (Enterprise Products Partners) after 
the effective date of the rule.
    During the meeting on February 1, 2016, the LPAC recommended that 
PHMSA modify the NPRM to (1) require reporting from gathering pipeline 
operators using streamlined forms and (2) set a 1-year implementation 
period for the annual reporting requirement and a 6-month 
implementation period for the accident reporting requirement.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the scope and timing of the requirements for gathering lines. 
Regarding the comment that the proposed reporting requirement of Sec.  
195.1(a)(5) exceeds PHMSA's statutory authority, PHMSA notes that the 
Federal Pipeline Safety Statutes state, in relevant part, ``[t]he 
Secretary may require owners and operators of gathering lines to 
provide the Secretary

[[Page 52277]]

information pertinent to the Secretary's ability to make a 
determination as to whether and to what extent to regulate gathering 
lines.'' 49 U.S.C. 60117(b). PHMSA has determined that, in order to 
decide whether and to what extent to regulate gathering lines, as 
permitted by Congress, PHMSA requires pertinent information about those 
pipelines, including elements of the data contained in annual, safety-
related condition, and incident reports. With this reporting 
requirement, PHMSA is not encroaching on the States' regulatory 
authority, nor creating new jurisdiction. Rather, PHMSA is collecting 
pertinent information to determine if future regulation is necessary 
for the statutory purpose of promoting pipeline safety.
    More specifically, PHMSA is collecting items in the annual report 
that primarily include the mileage count for those gathering lines 
currently unregulated, the diameters of those lines, and whether they 
are operating at greater or less than 20 percent SMYS. The goal of 
collecting this specific information is to provide PHMSA with a better 
understanding of the scope of the Nation's gathering pipeline 
infrastructure. As previously stated, recent data indicates PHMSA 
regulates only approximately 4,000 miles of the estimated 30,000 to 
40,000 miles of onshore hazardous liquid gathering lines in the United 
States. That means that as much as 90 percent of the onshore gathering 
line mileage is not currently subject to any minimum Federal pipeline 
safety standards, and little is known about that mileage.
    In requiring accident reports for otherwise unregulated gathering 
lines, PHMSA is collecting data that includes the underlying cause for 
the accident, where the accident was located and how it was reported to 
the operator, and a value for any property damage caused. This data 
will be essential to understanding and managing risk. PHMSA uses 
information reported by pipeline operators to identify trends, provide 
performance measures, and understand the causes and consequences of 
pipeline incidents. Reporting requirements are in place for all 
pipelines except for the gravity and gathering pipelines addressed by 
this final rule. Each year, the U.S. Coast Guard's National Response 
Center receives several notifications of hazardous liquid releases 
involving ``gathering lines,'' but details on these releases are not 
sufficient to understand the factors that contributed to the releases 
and the damages, or to evaluate whether the lines involved are 
gathering lines over which PHMSA has jurisdiction.\41\ The reporting 
requirements for gathering lines will help PHMSA have a more complete 
understanding of the risks these lines may pose.
---------------------------------------------------------------------------

    \41\ NRC data for 2010 through 2014 show 116 incidents 
categorized as ``pipeline'' incidents and that specifically include 
the term ``gathering'' in the incident description. Many more 
pipeline incidents could also be from gathering lines.
---------------------------------------------------------------------------

    PHMSA notes that one of its challenges is to understand and target 
risk, which requires a systematic approach to risk management, 
including a ``comprehensive understanding of the factors contributing 
to risk and the ability to focus resources in those areas that pose the 
greatest risk.'' One of PHMSA's strategies for dealing with this 
challenge is to improve data collection and analysis, collect the right 
data to evaluate risks from unregulated entities, and improve the 
transparency of information and public awareness of pipeline and 
hazardous materials safety issues. The long-term benefits of having 
better information may include reducing incidents, enhancing incident 
response, and increasing public confidence.
    As such, PHMSA is finalizing the requirement for operators of 
gathering lines to report information annually, starting 1 year from 
the rule's effective date, and to report accidents and safety-related 
conditions starting 6 months from the final rule's effective date. 
PHMSA considers these deadlines practicable in view of the scope of the 
information requested. To facilitate reporting and address commenters' 
concerns about providing clear instructions on data elements that must 
be filled out for gathering lines, PHMSA has modified its existing 
reporting form to provide clear instructions, including skip patterns, 
on the relevant sections that gathering line operators must fill out. 
In response to API's specific suggestions regarding operator 
qualification, control room management, leak detection, and HCA 
reporting, these revisions exempted rural gathering lines from any 
fields that involve ``Could Affect HCA'' data. PHMSA recognizes that 
operators who are not currently submitting data will have to register 
for an identifier, but PHMSA expects the burden on operators to do this 
is small. In its analysis, PHMSA assumed that a majority of the 
reporting of currently unregulated gathering lines would be done by 
operators who already have OPIDs. PHMSA estimates that, at a minimum, 
approximately 20 operators will need to submit information for 
gathering lines for the first time, and another 56 operators will add 
information about gathering lines to their existing annual reports. 
PHMSA estimates the total reporting burden at 402 hours per year, on 
average. See the revised RIA accompanying the final rule for additional 
detail.
    Some commenters requested that PHMSA clarify whether these 
reporting requirements applied to offshore gathering lines in State 
waters. As the purpose of the information collection is to evaluate the 
public risk posed by gathering lines, PHMSA found it appropriate to 
extend the reporting requirements to certain offshore gathering lines 
in State waters.
    In its proposal, PHMSA did not intend to require mapping or NPMS 
submissions for gathering lines. Under 49 U.S.C. 60132, only 
transmission line operators are required to submit mapping data for use 
in the NPMS; PHMSA does not have the explicit authority to collect NPMS 
data for gathering lines. PHMSA is therefore finalizing the rule 
without imposing this requirement on operators of gathering lines.
    Similar to requirements for gravity lines, PHMSA is not requiring 
telephonic reporting of accidents involving gathering lines to PHMSA at 
this time since such a requirement would not support the purpose of 
this data collection effort, which is to enable PHMSA to evaluate risk 
over time for potential future action. PHMSA notes that operators must 
still report spills to the National Response Center and other relevant 
authorities. PHMSA will reassess the utility of requiring notification 
for incidents involving gathering lines in a future rulemaking if the 
analyses suggest that such notifications would enhance prevention, 
preparedness, and response to hazardous liquid releases from gathering 
lines.
    Certain commenters also stated their belief that PHMSA neglected to 
account for the costs and burden associated with the initial compiling 
of the data needed to complete the forms. In many cases, the commenters 
suggested, information may not have been recorded or may not have been 
provided during mergers or acquisitions. PHMSA noted in the RIA that it 
expects operators to have the requested information readily available, 
as it is essential for pipeline operation and safety. PHMSA allows 
operators to enter ``unknown'' when values cannot be determined for 
certain data fields. In the burden estimate, PHMSA allotted time for 
operators to compile the proper data and organize it into the requested 
format. See the RIA for further details. PHMSA did not impose minimum 
safety standards on currently unregulated gathering lines, as some

[[Page 52278]]

commenters suggested, because the agency currently does not have data 
to analyze what risk, if any, those lines may pose to surrounding 
communities and environments. However, under these provisions, PHMSA 
will gather data on unregulated gathering lines and will use that data 
to determine whether additional safety regulations may be necessary.

C. Pipelines Affected by Extreme Weather and Natural Disasters

1. PHMSA's Proposal
    Recent events demonstrate the importance of ensuring that our 
Nation's waterways are adequately protected in the event of a natural 
disaster or extreme weather. PHMSA is aware that responsible operators 
might do such inspections; however, because it is not a requirement, 
some operators do not. Therefore, PHMSA proposed to require that 
operators perform an additional inspection within 72 hours after the 
cessation of an extreme weather event such as a hurricane or flood, an 
earthquake, a natural disaster, or other similar event.
    Specifically, PHMSA proposed that an operator must inspect all 
potentially affected pipeline facilities after an extreme weather event 
to help ensure that no conditions exist that could adversely affect the 
safe operation of that pipeline. The operator would be required to 
consider the nature of the event and the physical characteristics, 
operating conditions, location, and prior history of the affected 
pipeline in determining the appropriate method for performing the 
inspection required. The initial inspection must occur within 72 hours 
after the cessation of the event, defined as the point in time when the 
affected area can be safely accessed by available personnel and 
equipment required to perform the inspection. Based on PHMSA's 
experience and coordination with operators following natural disasters, 
PHMSA has found that 72 hours is reasonable and achievable in most 
cases. If an operator finds an adverse condition, the operator must 
take appropriate remedial action to best ensure the safe operation of a 
pipeline based on the information obtained as a result of performing 
the inspection. PHMSA specifically asked for comments on how operators 
currently respond to these events, what type of events are encountered, 
and if a 72-hour response time is reasonable.
2. Summary of Public Comment
    Some trade organizations recommended that certain requirements be 
eliminated altogether or consolidated to reduce what they considered to 
be duplicative of existing emergency planning requirements in Sec.  
195.402(e)(4).
    Commenters were nearly unanimous in requesting that PHMSA clarify 
the definition of extreme weather event, the 72-hour timeline, and the 
timeline for mitigating or repairing anomalies. The GPA recommended 
that PHMSA either define exactly which events require response and 
inspection or establish performance expectations without partially 
defining the criteria, while the County of Santa Barbara recommended 
that the proposed regulations specify a threshold at which action would 
be required. Congresswoman Lois Capps (California) recommended that 
PHMSA include definitions and/or citations of existing definitions for 
qualifying events and the responsible party for such a determination. 
Congresswoman Capps also recommended that PHMSA clarify the terminology 
for an ``appropriate method for performing the inspection'' after the 
event.
    In addition to clarification of the definition of extreme weather 
event, trade groups also requested clarification of the 72-hour 
timeline following an extreme weather event, including how they would 
determine the cessation of the event, what appropriate action they 
would need to take following an event, and how to address the 
possibility of continued danger facing personnel or issues with 
availability of personnel and resources following an event.
    API-AOPL recommended that PHMSA define cessation as the point in 
time when no further threats to personnel safety or equipment exist in 
the affected area, allowing for safe access by pipeline personnel and 
equipment. They also recommended that the 72-hour window commence only 
once personnel and equipment could safely access the affected area.
    Citizen groups and individuals requested that operators be required 
to proactively address known risks and vulnerabilities in advance of an 
extreme weather event. For example, one organization recommended 
additional requirements to identify areas that are particularly 
vulnerable to extreme weather events or natural disasters, (e.g., 
stream crossings, and to develop proactive preventive measures.) The 
Alaska Wilderness League et al. recommended mandatory prevention 
measures that include shutting down pipeline operations in case of an 
imminent flood to prevent spills such as the 2011 Exxon Mobil 
Yellowstone River spill. Citizen groups also requested immediate 
reporting to PHMSA when remedial action is required and that this 
information be made publicly available. The Environmental Defense 
Center requested that PHMSA provide specific, enforceable requirements 
for shutdown or other remedial action should an inspection reveal 
damage or anomalies, and that PHMSA clarify the type of events covered 
and the inspection methodology required.
    Finally, the OOC recommended that PHMSA coordinate with BSEE and 
the U.S. Coast Guard for activities that occur after hurricanes.
    During the meeting on February 1, 2016, the LPAC recommended that 
PHMSA modify the NPRM to (1) include landslides as an extreme weather 
event, (2) clarify that other similar events are those likely to damage 
infrastructure, and (3) require operators to inspect all potentially 
affected pipeline facilities to detect conditions that could adversely 
affect the safe operation of the pipeline. The LPAC also recommended 
that PHMSA modify the language regarding the inspection method to 
require operators to consider the nature of the event and the physical 
characteristics, operating conditions, location, and prior history of 
the affected pipeline in determining the appropriate method for 
performing the initial inspection to determine damage and the need for 
additional assessments. Finally, the LPAC recommended that PHMSA 
clarify that the inspection must commence within 72 hours after the 
cessation of the event, which is defined as the point in time when the 
affected area can be safely accessed by the personnel and equipment, 
accounting for personnel and equipment availability.
3. PHMSA Response
    PHMSA disagrees with the comments stating the provisions at Sec.  
195.414 are unnecessary and duplicate operation and maintenance (O&M) 
manual requirements already contained in the response plan requirements 
under Sec.  195.402. While Sec.  195.402 does require that operators 
include certain ongoing monitoring measures in their O&M manuals, the 
proposed Sec.  195.414 is much more specific in requiring that 
operators take appropriate remedial action to best ensure the safe 
operation of a pipeline based on the information obtained as a result 
of performing the post-event inspection required under paragraph (a) of 
this section. This will ensure that operators take the prescribed 
actions; having measures described in an operator's O&M manual, as 
previously required, is not equivalent to action. PHMSA maintains that 
separate and more specific requirements are

[[Page 52279]]

warranted to best ensure public safety and environmental protection 
following extreme events. Additionally, PHMSA notes that reporting is 
coordinated with BSEE, the U.S. Coast Guard, and other agencies under 
existing notification procedures if the assessment determines there was 
a release involving their areas of responsibility. Both 49 CFR parts 
194 and 195 require operators to report spills to the National Response 
Center.
    PHMSA appreciates the feedback provided by the commenters regarding 
the need for greater clarity in the definition of extreme events and 
natural disasters and expectations on the timing and scope of post-
event inspections. In developing the requirements, PHMSA sought to 
balance being explicit regarding the types of events that could 
increase the risk of a release and therefore require inspections, with 
providing sufficient flexibility to account for diverse geographical 
and pipeline design factors. PHMSA recognizes that the language 
recommended by the LPAC is useful in striking this balance and adopted 
most its revisions in the final rule under Sec. Sec.  195.414(a), (b), 
and (c). PHMSA is removing the language ``other similar event'' as 
PHMSA found the phrase to be vague and unnecessary to accomplish the 
goals of the provision but is maintaining the LPAC's recommended 
language regarding the ``likelihood to damage infrastructure.'' Per the 
finalized requirement, operators must inspect all potentially affected 
pipeline facilities following extreme weather events or natural 
disasters with the likelihood of damaging infrastructure, such as named 
hurricanes or tropical storms; floods that exceed the high-water banks 
of rivers, shorelines or creeks; and landslides or earthquakes 
occurring within the area of a pipeline, in order to detect conditions 
that could adversely affect the safe operation of that pipeline. As 
discussed earlier in this document, the conditions that trigger this 
requirement are those that have the potential to cause river scour, 
soil subsidence, or earth movement, all of which can subject a pipeline 
to additional external loads and forces and cause the pipeline to fail. 
Pipeline operators are already required to understand and analyze the 
impact such weather events and natural disasters may have on their 
systems based the physical characteristics, operating conditions, 
location, and prior history of susceptible pipelines.
    PHMSA retained the remedial actions unchanged from the proposal. 
While PHMSA intends for operators to inspect pipelines as soon as 
possible after an event ends, PHMSA also agrees with commenters that 
personnel safety is paramount. Accordingly, PHMSA clarified that the 
cessation of the event occurs as soon as it is safe for personnel and 
equipment to access the area. Operators are responsible for determining 
when each site is safe enough for entry.
    In response to commenters who sought greater flexibility in the 
timing of the inspections by leaving it up to the operators, PHMSA 
disagrees and maintains that setting clear and consistent timelines is 
essential to ensuring that all operators detect and address any issues 
promptly. The final rule does provide a fallback to operators who must 
delay the start of actions beyond this time due to availability of 
equipment, but these operators must notify the Regional Director. This 
addition to the LPAC-approved language allows operators to retain 
flexibility due to unavailable equipment, while ensuring accountability 
and prompt action. PHMSA considers 72 hours to be a reasonable period 
for mobilizing personnel and equipment following an event.
    In response to commenters who expressed concerns that inspections 
cannot be reasonably be completed within the 72-hour window, PHMSA 
notes that the proposal did not require completion of the inspections 
within 72 hours, and neither does the final rule; PHMSA recognizes that 
this needed to be clarified in the rule text and has done so in the 
final rule. The final rule accordingly describes the actions it expects 
operators to perform, starting within 72 hours after the cessation of 
the event. Recognizing that some actions will need to be site-specific, 
PHMSA provides flexibility to operators to determine the measures that 
are appropriate to the event, pipeline design, and circumstances.
    PHMSA is receptive to the recommendation that operators should take 
precautionary measures to minimize exposure in advance of and during an 
extreme event (e.g., reducing operating pressure or shutting down a 
pipeline), and notes that the current IM regulations require operators 
to know and understand risks to their system, which includes the threat 
of extreme events such as flooding or wind damage. To execute their IM 
programs and assessments on non-HCA lines as per this final rule, 
operators will need to have pipeline system information to address 
risks to their systems. Operators will use the information they have 
gathered on their entire pipeline system to monitor conditions and 
determine any anticipated risks to their pipelines, including extreme 
weather events. Given that the existing IM regulations require 
preventive and mitigative measures for HCAs, which often include river 
crossings, it is appropriate for this section to address post-natural 
disaster inspections for damage specifically.

D. Periodic Assessment of Pipelines Not Subject to IM

1. PHMSA's Proposal
    PHMSA proposed to require integrity assessments for pipeline 
segments in non-HCAs. PHMSA believes that expanded assessment of non-
HCA pipeline segments areas will provide operators with valuable 
information they may not have collected if regulations were not in 
place; such a requirement would help ensure prompt detection and 
remediation of corrosion and other deformation anomalies in all 
locations, not just HCAs. Specifically, the proposed Sec.  195.416 
would require operators to assess non-HCA (non-IM) pipeline segments 
with an ILI tool at least once every 10 years, which allows operators 
to prioritize HCA assessments. PHMSA proposed to allow other assessment 
methods if an operator provides OPS with prior written notice that a 
pipeline is not capable of accommodating an ILI tool. Such alternative 
technologies would include hydrostatic pressure testing or appropriate 
forms of direct assessment.
    Although imposing the full set of IM requirements in Sec.  195.452 
on non-HCA pipeline segments was not proposed, operators would be 
required to comply with the other provisions in 49 CFR part 195 in 
implementing the requirements in Sec.  195.416. That includes having 
appropriate provisions for performing periodic assessments and any 
resulting repairs in an operator's procedural manual (see Sec.  
195.402); adhering to the recordkeeping provisions for inspections, 
tests, and repairs (see Sec.  195.404); and taking appropriate remedial 
action under proposed Sec.  195.422, which, based on the existing IM 
repair criteria at Sec.  195.452(h), identified specific types of 
anomalies and the timeframes by which they must be remediated. 
Operators would also follow the requirements for ``discovery of 
condition,'' where the discovery of a condition occurs when an operator 
has adequate information to determine that a condition exists. The 
operator must promptly, but no later than 180 days after an assessment, 
obtain sufficient information about a condition to determine whether 
the condition could adversely affect the safe operation of the 
pipeline, unless 180 days is impracticable as determined by

[[Page 52280]]

PHMSA. PHMSA sought public comment on the alternatives it considered 
under this specific proposal and on quantifying these alternatives in 
the regulatory impact analysis.
2. Summary of Public Comment
    Trade organizations offered comments and language revisions on the 
methods and requirements included in the periodic assessments, 
implementation period, inspection intervals, and exemptions for lower 
risk pipelines. Enterprise Products Partners requested that operators 
be afforded the latitude they have under current IM regulations to 
determine the actual threats to pipeline integrity present on a given 
segment and to tailor their integrity assessment program accordingly. 
For instance, Enterprise suggested that PHMSA revise the proposal to 
clarify that a crack tool is not required for every ILI assessment, 
stating specifically that ``an additional ILI crack tool is beneficial 
only when there is an identified threat to the pipeline segment that 
could result in cracks, such as cyclic fatigue. Yet PHMSA proposes to 
require a [crack tool] in all circumstances and on every pipeline 
segment.'' Other trade organizations echoed this and requested that 
PHMSA incorporate alternatives to ILI tools for periodic assessments 
into the rule. Trade organizations also recommended that PHMSA ensure 
the rule is consistent with existing IM rules, including the 
reassessment intervals and implementation period. The Texas Pipeline 
Association requested that reassessment intervals be based on sound 
engineering judgement and industry consensus standards. Finally, trade 
organizations recommend that PHMSA limit and specify the type of 
pipelines to which the requirement would apply, with some commenters 
requesting specific exemptions for short lines and CO2 
pipelines. API-AOPL requested that PHMSA clarify that operators would 
not need to run assessments on idle or out-of-service pipelines. API-
AOPL also requested that PHMSA clarify that it intends for the 
requirements to include transmission lines only. Finally, the GPA 
requested that PHMSA rely on American Society of Nondestructive Testing 
(ASNT) ILI PQ as the standard for data analysis rather than the current 
language ``qualified by knowledge, training, and experience.'' The GPA 
submitted additional comments to PHMSA on March 24, 2016, expressing 
concerns that PHMSA misrepresented aspects of this proposal during the 
LPAC meeting. In the LPAC meeting the GPA claimed that PHMSA asserted 
that currently regulated gathering lines are subject to assessments; 
the GPA believes that this statement was inaccurate and led to a vote 
by the committee that was not based on accurate facts. Further, the GPA 
suggested that ``it is possible there are gathering lines in non-rural 
areas which do not meet the Census Bureau definitions for high or other 
population areas. Thus, when properly applying the regulations as 
currently written, there are gathering lines, which are regulated by 
PHMSA and its state partners for safety purposes that are not subject 
to periodic assessments.''
    Trade organizations also commented on the cost of expanding 
requirements for pipelines located outside of HCAs. The Texas Pipeline 
Association commented that raising the level of regulation on 
facilities outside of HCAs will redirect resources from high-risk areas 
to lower-risk areas. They requested that PHMSA consider the costs to 
operators of the proposed changes related to facilities outside of 
HCAs. The OOC also commented that offshore lines present unique 
challenges that make them ill-fitted for ILI technology and hydrotests.
    Other groups and individuals commented on the methods and 
requirements included in the periodic assessments, inspection 
intervals, and additional requirements. A 5-year inspection interval 
was generally favored by citizen groups and individuals, including the 
Alliance for Great Lakes Et al. Congresswoman Capps highlighted that a 
3-year interval between inspections had proven to be inadequate to 
detect corrosion that caused the Plains All American oil pipeline 
rupture in May 2015. These commenters also requested clarification that 
alternative methods of assessment must account for inspection along the 
entire pipeline both inside and outside HCAs and expressed concern with 
waivers for ILI tools or the use of direct assessment.
    The NTSB requested that PHMSA harmonize the gas and liquid 
regulations to the maximum extent practicable and cautioned that direct 
assessment is an ineffective alternative technology for IM when 
applying the 10-year assessment requirement for the integrity of an 
entire pipeline. They recommended that the IM program encompass a broad 
range of available IM technologies including, but not limited to, ILI, 
magnetic flux leakage, ultrasonic testing, and tests directed at 
determining the integrity of the pipe coating.
    Finally, some citizen groups and individuals requested that 
inspection reports be made publicly available and that operators be 
required to submit primary inspection results and data to PHMSA. The 
Environmental Defense Center recommended third-party verification of 
inspection reports based on corrosion underreporting. These groups also 
requested risk assessment on non-IM pipelines and annual inspections 
for all federally regulated hazardous liquid pipelines.
    During the February 1, 2016, meeting, the LPAC recommended PHMSA 
modify the NPRM to clarify its application to pipelines regulated under 
Sec.  195.1 that are not subject to the IM requirements in Sec.  
195.452. The LPAC also made additional language recommendations to 
clarify the method of the assessment when ILI tools are impracticable, 
including pressure tests, external corrosion direct assessment, or 
other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters. PHMSA 
notes that the LPAC, with minor tweaks, found the provision for 
requiring operators to perform these periodic assessments on all 
covered pipelines not subject to the integrity management requirements 
under Sec.  195.452 to be a cost-effective, practicable, and 
technically feasible provision.
    However, several commenters noted challenges and cost-benefit 
concerns with assessing offshore lines and regulated rural gathering 
lines as a part of this proposal. In this final rule, PHMSA is limiting 
the assessment requirement to onshore, non-HCA, non-gathering lines 
that can accommodate inline inspection tools.
    Under the current regulations, PHMSA notes that approximately 45 
percent of hazardous liquid pipelines are required to be assessed per 
the IM requirements by being located within an HCA or because they can 
affect an HCA. PHMSA has determined that, through this provision, most 
onshore non-HCA mileage will be assessed at a consistent rate. Further, 
as pipeline operators continue to replace pipe through modernization 
projects and repairs, PHMSA assumes that virtually all the Nation's 
pipeline mileage will be piggable within the next few decades.
    In the NPRM, PHMSA did not intend for the requirements applicable 
to lines outside of HCAs to be more stringent than those applicable to 
lines in HCAs. PHMSA agreed with the commenters and the LPAC that it is 
appropriate to provide the same flexibility for the assessment of lines 
outside of HCAs as

[[Page 52281]]

lines within HCAs, but PHMSA notes that many of these concerns appeared 
to be in response to PHMSA's requirement to assess all non-HCA lines, 
even ones that were not readily piggable. As discussed above, this 
final rule's non-HCA assessment requirement now applies to piggable, 
onshore transmission line only. This final rule does allow operators to 
use pressure testing, direct assessment, or other technology in cases 
when in-line inspections are impracticable. PHMSA has determined that 
ILI tools may not be available for all pipe diameters and threats being 
assessed, and providing operators the ability to use these other 
assessment methods on piggable lines is appropriate at this time.
    Further, per the comments received from commenters, including API 
and Enterprise, related to the use of crack tools, PHMSA has revised 
the final rule, at both Sec. Sec.  195.416 and 195.452, to require 
crack tools only when there is an identified or probable risk or threat 
supporting their use. For example, if operators have identified a 
pipeline segment with identified or probable risks or threats related 
to corrosion and deformation anomalies, including dents, gouges, or 
grooves, then the operator must assess that segment with a tool capable 
of detecting those anomalies. Similarly, operators should assess 
pipeline segments with an identified or probable risk or threat related 
to cracks using a tool capable of detecting crack anomalies. 
Essentially, operators should always be selecting an appropriate 
assessment tool based on the pertinent threats to a given pipeline 
segment that have been identified by an operator's risk assessment. An 
operator's risk assessment should always be driving its integrity 
assessments and the integrity management program. An operator cannot 
properly maintain its pipeline if it does not know what threats to 
which the pipeline is susceptible to and which tools the company should 
be selecting to assess those threats. These threats can include, but 
are not limited to, pipe that may have manufacturing defects or have 
otherwise experienced in-service incidents.
    Under the existing requirements of Sec.  195.452(c)(1) (after which 
PHMSA modeled the new assessment requirements in Sec.  195.416), 
operators must select an assessment method capable of assessing seam 
integrity and of detecting corrosion and deformation anomalies if the 
applicable pipe is low-frequency ERW pipe or lap-welded pipe 
susceptible to longitudinal seam failure. PHMSA has interpreted and 
intended the phrase ``susceptible to seam failure'' to apply to both 
low-frequency ERW pipe and lap-welded pipe. In this final rule, PHMSA 
has expanded the assessment provisions to require operators to use a 
tool or tools capable of assessing seam integrity, cracking, and of 
detecting corrosion and deformation anomalies on low-frequency ERW 
pipe, pipe with a seam factor less than 1.0 (as defined in Sec.  
195.106(e)) \42\)), or lap-welded pipe susceptible to longitudinal seam 
failure. Certain stakeholders may interpret this requirement to mean 
that these tools will need to be run on every segment of low-frequency 
ERW pipe, pipe with a seam factor of less than 1.0, or lap-welded pipe. 
However, PHMSA only explicitly requires the use of these tools for 
segments of low-frequency ERW pipe, pipe with a seam factor less than 
1.0, or lap-welded pipe when these types of pipe are determined by an 
operator to be susceptible to longitudinal seam failure based on 
excavation findings, examinations, leaks, failures, pressure tests, 
inline inspections, other operating history, and the manufacturing 
history of the pipe vintage and its history of seam leaks and failures.
---------------------------------------------------------------------------

    \42\ 49 CFR 195.106(e) has seam factors for pipe seams that need 
to be de-rated for maximum operating pressure determination. A de-
rated seam factor would be below 1.0 and include furnace lap welded 
and furnace butt welded pipe seams.
---------------------------------------------------------------------------

    Similarly, PHMSA found that the proposed requirements for 
``discovery of condition'' under Sec.  195.416 were more stringent than 
the revisions proposed for Sec.  195.452. To be consistent with the 
revised requirements under Sec.  195.452 regarding the discovery of 
condition, the operator has 180 days to obtain sufficient information 
on conditions and make the required determinations, unless the operator 
can demonstrate that the 180-day timeframe is impracticable. In cases 
where an operator does not have adequate information within 180 days 
following an assessment, pipeline operators must notify PHMSA and 
provide an expected date when that information will become available. 
These revisions will provide consistency for the discovery of condition 
across all regulated HCA and non-HCA lines.
    PHMSA also agreed with the commenters and the LPAC that it is 
necessary to clarify which pipelines fall under the non-HCA assessment 
requirements. However, upon further review, PHMSA found that adopting 
the LPAC-recommended language for Sec.  195.416(a), by clarifying 
application of this requirement to pipelines regulated under Sec.  
195.1 that are not subject to the IM requirements in Sec.  195.452, 
would extend this requirement beyond PHMSA's or the LPAC's intent and 
would cover facilities not previously intended, such as pump stations. 
Therefore, instead of strictly adopting the language proposed by the 
LPAC, PHMSA is instead specifying that these requirements apply to 
onshore, piggable line pipe not covered under the IM requirements, 
including the relevant line pipe within pump stations, but not other 
appurtenances and components like metering stations, tanks, etc. 
Further, PHMSA is not requiring IM 5-year assessments but is requiring 
operators to continue the implementation of the preventive and 
mitigative measures under IM (Sec.  195.452(i)) for appurtenances, 
pumps, tanks, etc., for these facilities that could affect a HCA. PHMSA 
believes this clarification captures the intent of the LPAC members.
    In response to the GPA's suggestion for an alternative standard for 
data analysis, PHMSA's existing process for data analysis has been 
through a rigorous rulemaking process. PHMSA is not incorporating 
alternative standards into this rule making that were not included at 
an earlier rulemaking stage and were not subject to public comment.
    Regarding the GPA's other concern as to whether PHMSA provided the 
LPAC with inaccurate information concerning the extent to which 
operators are already required to perform assessments on gathering 
lines versus the new assessment requirements PHMSA was proposing in the 
NPRM, PHMSA notes that on pages 180 and 181 of the LPAC meeting 
transcript PHMSA clearly states that it is proposing subjecting 
currently regulated rural gathering lines to periodic assessment and 
repair requirements in Sec. Sec.  195.416 and 195.422, saying, ``When 
it comes to the gathering lines that we don't currently regulate, 
[that] the regulations don't currently address, the only requirements 
we're applying will be the reporting requirements that we discussed 
prior. In the [NPRM], when it came to regulated rural gathering lines, 
we proposed to subject them to the assessment requirements in [Sec.  
195.]416 and [Sec.  195.]422. There's actually a proposal in the NPRM 
to link the two sections together, but it would not require that lines 
that are currently, today, not regulated to be assessed.'' The 
statement by PHMSA at the LPAC meeting that the GPA questions states 
that regulated rural gathering lines have an assessment requirement in 
the NPRM as opposed to currently unregulated gathering lines, which do 
not. Further discussion and voting at the LPAC meeting indicated that 
the committee members fully

[[Page 52282]]

understood PHMSA's proposal, with committee members clarifying the 
definition by asking it to be revised to ``transmission and regulated 
gathering lines'' and noting ``there's clarity with this [definition] 
now.''
    Regarding the GPA's other comment on the possibility of the 
existence of gathering lines in non-rural areas that are not assessed, 
PHMSA notes this is incorrect. Currently, the only regulated gathering 
lines that are not subject to assessment requirements are regulated 
rural gathering lines, which, per their name, are in rural areas. Under 
existing Sec.  195.1(a)(4), any onshore gathering lines located in non-
rural areas and gathering lines located in Gulf of Mexico inlets are 
covered by 49 CFR part 195, and if these gathering lines are within 
HCAs or could affect HCAs, they are subject to the full IM program 
requirements, including integrity assessments, under the current Sec.  
195.452. As defined in Sec.  195.2, a ``rural area'' means ``outside 
the limits of any incorporated or unincorporated city, town, village, 
or any other designated residential or commercial area such as a 
subdivision, a business or shopping center, or community development.'' 
To exist outside of a ``rural area'' as that term is defined under 
Sec.  195.2 (i.e., a ``non-rural'' pipeline), a pipeline would have to 
be inside (rather than outside) the limits of any incorporated or 
unincorporated city, town, etc. Per the definition of an HCA at Sec.  
195.450, a pipeline in such an area would be in an HCA, and therefore 
would be regulated and subject to assessment requirements. Therefore, 
with the exception of regulated rural gathering lines, operators should 
be assessing all other regulated gathering lines per their IM programs.
    PHMSA does not agree with API-AOPL that clarification is needed in 
the rule on the issue of ``idle'' pipelines. The Federal PSR list only 
two statuses for a pipeline: (1) In-service/active; or (2) 
``abandoned,'' which the PSR defines as ``permanently removed from 
service.'' Although operators frequently refer to a pipeline that is 
not being actively used as ``idle,'' PHMSA has no current operational 
designation for an ``idle'' line. Unless they are abandoned in 
accordance with applicable procedures, pipelines that are not currently 
in use must meet all the requirements of the Federal PSR, including 
compliance with IM regulations if those pipelines are in HCAs. On March 
17, 2014, a pipeline leaked crude oil into a highly populated suburb of 
Los Angeles, CA (Wilmington, CA), releasing an estimated 1,200 gallons 
of oil.\43\ The pipeline was never purged and filled with inert 
material as per the operator's procedures required by the regulations, 
and the operator (who bought the pipeline from another operator), 
believed the pipeline was ``abandoned.'' This demonstrates the fact 
that pipelines that have been ``idled'' can still present a safety risk 
and must be treated as active pipelines. Further, as operators can 
restart ``idle'' lines and transport product later, it is important 
that operators maintain these lines to the same level of safety and 
standards as an active, in-service line. Accordingly, PHMSA expects 
operators of ``idle'' lines to perform assessments and adhere to all 
the applicable regulations based on the line's location.
---------------------------------------------------------------------------

    \43\ Jeff Gottlieb: ``Phillips 66 oil line in Wilmington blamed 
for 1,200-gallon spill,'' Los Angeles Times, March 18, 2014. http://articles.latimes.com/2014/mar/18/local/la-me-0319-crude-oil-20140319.
---------------------------------------------------------------------------

    PHMSA considered the requests it received to make inspection 
reports for non-HCA lines publicly available and to require third-party 
inspection report verification. PHMSA determined that promulgating 
those requirements would make assessing non-HCA lines more burdensome 
than assessing HCA lines.
    Regarding requests that PHMSA require non-HCA inspections at 5-year 
intervals to ensure a larger number of populations and properties are 
protected, PHMSA notes that setting the non-HCA assessment interval to 
5 years would make it equal to that for lines in HCAs. Lowering the 
non-HCA assessment period to any time below 5 years would make it more 
stringent than the requirement for HCAs and would not allow operators 
to prioritize those higher-consequence areas first. Similarly, 
requiring a yearly inspection of all hazardous liquid pipelines, as 
some commenters suggested, would be overly burdensome and would work 
against risk-based prioritization.
    Many commenters also requested that PHMSA require operators to 
perform risk assessments on non-IM pipelines. As discussed in the 
previous section on extreme weather events, PHMSA expects operators 
will need to have a certain amount of information on their HCA and non-
HCA pipelines, including the environment in which they operate, for 
them to properly assess risk and the current condition of their 
pipeline system and to select the proper tool(s) for an adequate threat 
analysis. Operators cannot properly perform assessments if they do not 
know or understand the ``as-is'' state of their pipeline and any 
potential or actual threats. This information is required to comply 
with Sec.  195.401(a), which states that no operator may operate or 
maintain its pipeline systems at a level of safety lower than that 
required by subpart F of 49 CFR part 195 and the procedures it is 
required to establish under Sec.  195.402(a). Therefore, PHMSA expects 
operators will already be performing a level of risk analysis on non-
HCA lines as well as HCA lines.

E. IM and Non-IM Repair Criteria

1.a PHMSA's Proposal for Sec.  195.452 (IM Repairs)
    In the NPRM, PHMSA proposed modifying criteria in Sec.  195.452(h) 
for IM repairs to:
     Categorize bottom-side dents with stress risers, pipe with 
significant stress corrosion cracking, and pipe with selective seam 
weld corrosion as immediate repair conditions;
     Require immediate repairs whenever the calculated burst 
pressure is less than 1.1 times MOP;
     Eliminate the 60-day and 180-day repair categories; and
     Establish a new, consolidated 270-day repair category.
1.b PHMSA's Proposal for Sec.  195.422 (Non-IM Repairs)
    PHMSA also proposed to amend the requirements in Sec.  195.422 for 
performing non-IM repairs by:
     Applying the criteria in the immediate repair category in 
Sec.  195.452(h); and
     Establishing an 18-month repair category for hazardous 
liquid pipelines that are not subject to IM requirements.
2. Summary of Public Comment
    Citizen groups and individuals expressed concern with the changes 
to the repair timeline categories. The Alliance for Great Lakes et al. 
requested that PHMSA maintain the 180-day repair timeframe for all 
repairs that are not classified as immediate, and the Pipeline Safety 
Trust (PST) did not see justification for the 18-month and 
``reasonable'' time frames added for repairing pipelines outside of 
HCAs. API-AOPL requested a reasonable timeframe to address repairs in 
offshore pipelines that considers the type of repair and permit that 
might be involved. ETP recommended that PHMSA change the 270-day and 
18-month criteria to 1-year and 2-year criteria to assist operators 
with planning, budgeting, and scheduling.
    Enterprise Products Partners suggested specific language to clarify 
that Sec.  195.422 would apply only to pipelines not subject to IM 
requirements in Sec.  195.452 and those determined not to have the 
potential to affect HCAs.

[[Page 52283]]

API-AOPL also expressed concern that PHMSA might apply these criteria 
beyond non-HCA transmission lines to gravity and gathering lines 
located offshore and recommended explicit language to state that Sec.  
195.422 does not apply to gravity or gathering lines. The GPA requested 
that PHMSA clarify the applicability of this section to out-of-service, 
``idle'' pipelines.
    Commenters also asked for additional standards for conditions 
triggering repairs. For example, one public safety organization 
requested a more stringent standard for the amount of metal loss that 
triggers ``immediate repair,'' whereas the Alliance for Great Lakes et 
al. recommended that PHMSA establish standards for the prevention, 
detection, and remediation of significant stress corrosion cracking and 
stress corrosion cracking.
    The IPAA commented that PHMSA did not address whether resources 
exist to make the additional repairs that would be required, nor did it 
demonstrate a nexus between existing risk and the more conservative 
repair requirements that justify the potential costs, especially when 
considering regulated gathering lines. The GPA requested documentation 
on the basis for requiring the same repair criteria for non-gathering 
lines as the repair criteria for pipelines affecting HCAs. Western 
Refining recommended that PHMSA exempt pipeline segments that normally 
operate at a low pressure from the pressure reduction requirement. API-
AOPL recommended that PHMSA add an immediate repair condition for crack 
anomalies at a 70 percent nominal wall thickness and an 18-month repair 
condition on dents with corrosion. API-AOPL also recommended that PHMSA 
include a ``Scheduled Conditions'' repair condition for non-HCA lines, 
which would require an operator to make a report prior to the year when 
a calculation of the predicted remaining strength of the pipe 
(including allowances for growth and tool measurement error) shows a 
predicted burst pressure at less than 1.1 times the MOP at the location 
of the anomaly. This recommendation aimed to mitigate the potential for 
pressure-limiting, immediate features before the next ILI. Enterprise 
Products Partners recommended language to provide operators with 
flexibility to determine the severity of the reported metal loss 
indication and its potential impact on the integrity of the pipeline by 
setting the dent threshold as corroded areas deeper than 20 percent of 
the nominal wall thickness or where an engineering analysis indicates a 
reduction in the safe operating pressure of the dented area.
    API-AOPL and AGA recommended eliminating the SCC and SSWC immediate 
repair criteria. The AGA also requested that PHMSA allow pipeline 
operators to prioritize the repair of HCA segments over non-HCA 
segments. The GPA was also concerned that PHMSA's definition of SCC was 
based on the use of the word ``significant,'' because the term is 
subjective and PHMSA's proposed descriptors do not include all the 
variables that influence SCC behavior and is therefore very incomplete 
for assigning an ``actionable'' status for all instances.
    The PST requested that PHMSA change Sec.  195.563(a) to require 
that constructed, relocated, replaced, or otherwise changed pipelines 
must have cathodic protection within 6 months instead of 1 year, and 
they also requested that PHMSA require operators to know what type of 
pipe is in the ground and set the MOP appropriately, or test the pipe 
with an appropriate hydrotest to demonstrate a safe MOP.
    During the meeting of February 1, 2016, the LPAC recommended that 
PHMSA modify the NPRM to include recognized industry engineering 
analysis regarding dents and cracks to determine they are non-injurious 
and do not require immediate repair, and to give full and equal 
consideration to the stakeholder comments that were considered during 
the LPAC discussion.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters. PHMSA 
proposed revisions to the IM repair criteria to provide operators 
greater flexibility regarding the repair timeframes for certain 
anomalies, provide additional clarification regarding specific anomaly 
types, and address pipe cracking issues both the agency and the NTSB 
had identified following the incident near Marshall, MI, especially 
regarding stress corrosion cracking and selective seam weld corrosion. 
PHMSA also proposed to apply these changes with some modifications to 
non-HCAs to provide flexibility to operators and allow the risk-based 
prioritization of repairs.
    PHMSA notes that the LPAC, with certain suggestions, found the 
changes to both the non-HCA repair criteria and the HCA repair criteria 
to be cost-effective, practicable, and technically feasible provisions, 
and these provisions seemed to have wide stakeholder support following 
the ANPRM stage. However, PHMSA determined as part of the review 
process that it needs to gather additional data, including with respect 
to cost-benefit information, and to assess new technologies and 
practices before promulgating the proposed changes for non-HCA 
pipelines in this final rule. Based on this, PHMSA has decided to 
separate the repair-criteria provisions from this final rule and 
intends to issue a supplemental notice of proposed rulemaking where 
PHMSA would further analyze developing technology and practices, 
anomaly types and repair timeframes, and engineering critical 
assessment methods. This path will also provide commenters an 
additional opportunity to provide input on an important part of the 
regulations. PHMSA will incorporate any relevant discussion it would 
have included in this section of this rulemaking when discussing repair 
criteria in the supplemental notice. Therefore, for the purposes of 
this final rule, PHMSA is retaining the existing non-IM repair language 
at Sec.  195.401(b)(1) and the existing IM repair language at Sec.  
195.452(h).
    For non-IM pipelines, Sec. Sec.  195.401(b)(1), 195.585, and 
195.587 outline the requirements for non-integrity management pipeline 
repairs. Section 195.401(b)(1) requires operators that discover any 
condition that could adversely affect the safe operation of its 
pipeline system, they must correct the condition within a reasonable 
time. However, if the condition is of such a nature that it presents an 
immediate hazard to persons or property, the operator may not operate 
the affected part of the system until it has corrected the unsafe 
condition. For IM pipelines, PHMSA expects operators to continue to 
follow the existing regulations in Sec. Sec.  195.401(b)(2) and 
195.452(h) as they are written and repair the listed anomaly types 
within the specified timeframes.

F. Leak Detection Requirements

1. PHMSA's Proposal
    With respect to new hazardous liquid pipelines, PHMSA proposed to 
amend Sec.  195.134 to require that all new lines be designed to have 
leak detection systems, including pipelines located in non-HCA areas.
    With respect to existing pipelines, 49 CFR part 195 contains 
mandatory leak detection requirements for only those hazardous liquid 
pipelines that could affect an HCA. Congress included additional 
requirements for leak detection systems in section 8 of the 2011 
Pipeline Safety Act. That legislation requires the Secretary to submit 
a report to Congress, within 1 year of the enactment date, on the use 
of leak detection systems, including an analysis of the technical 
limitations and the practicability, safety benefits, and

[[Page 52284]]

adverse consequence of establishing additional standards for the use of 
those systems. Congress authorized the issuance of regulations for leak 
detection if warranted by the findings of the report.
    Based on information available to PHMSA including post-accident 
reviews and the Kiefner Report, PHMSA believes the need to strengthen 
the requirements for leak detection systems is clear. In addition to 
modifying Sec.  195.444 to require a means for detecting leaks on all 
portions of a hazardous liquid pipeline system including non-HCA areas, 
PHMSA proposed that operators perform an evaluation to determine what 
kinds of systems must be installed to adequately protect the public, 
property, and the environment. The proposed amendment to Sec.  195.11 
extended these new leak detection requirements to regulated onshore 
gathering lines.
2. Summary of Public Comment
    Trade organizations expressed concerns with requiring operators of 
gathering lines and certain non-gathering lines to install and maintain 
leak detection systems. The GPA commented that PHMSA's proposal is not 
appropriate for gathering lines at this time, citing findings of the 
``Liquids Gathering Pipelines: A Comprehensive Analysis'' study,\44\ 
which concluded that (1) gathering lines present unique challenges to 
leak detection technologies; (2) gathering lines are constantly 
transition in flow, pressure, and line-packing; (3) benefits do not 
justify the cost for leak detection systems applied to gathering lines; 
and (4) there is a lack of demonstrated technology to reliably detect 
spills. The IPAA noted that PHMSA should not proceed with expanding 
leak detection systems because it had not performed an analysis of the 
practicability of establishing technically, operationally, and 
economically feasible standards for the capability of such systems to 
detect leaks, and the safety benefits and adverse consequences of 
requiring operators to use leak detection systems. The GPA also 
recommended that PHMSA provide relief for short sections of pipeline 
less than 1 mile in length and lines located within facilities where 
they pose no risk to the public. API-AOPL and OOC requested 
clarification that this section would not apply to offshore gathering 
lines. The commenters requested implementation periods ranging between 
5 years (API-AOPL) and 7 years (GPA). Finally, the Texas Pipeline 
Association commented on the cost of complying with this regulation for 
lines outside of HCAs and the redirection of resources from high-risk 
areas to lower-risk areas that they allege would occur.
---------------------------------------------------------------------------

    \44\ Energy and Environmental Research Center, University of 
North Dakota, 2015, https://www.undeerc.org/bakken/pdfs/EERC%20Gathering%20Pipeline%20Study%20Final%20Dec15.pdf.
---------------------------------------------------------------------------

    Citizen groups and other commenters requested minimum standards for 
leak detection systems, and applicability to all hazardous liquids 
lines. The Pipeline Safety Coalition recommended the inclusion of (1) 
all existing hazardous liquids lines and all lines under construction 
at rulemaking; (2) prescriptive standards for leak detection 
classifications; (3) prescriptive standards for acceptable leak 
detection procedures and devices; and (4) standards that are specific 
to location, community, and environmentally sensitive areas. The 
Alliance for Great Lakes et al. commented that computational pipeline 
monitoring systems detect only large ruptures and involve significant 
data interpretation and analysis. They expressed concerns regarding the 
lack of system standards and guidance on how to assess the 
effectiveness of a given leak detection system on a given pipeline due 
to significant variations in pipeline design. The Environmental Defense 
Center also recommended that automatic shutdown systems be required.
    Beyond requirements for new pipelines, some commenters also 
requested a clear schedule for leak detection system for pipelines 
undergoing construction. For example, the NTSB urged PHMSA to include 
language that specifies a distinct trigger date for leak detection 
implementation on pipelines that have already started construction but 
would not yet be operational when the new regulation becomes effective.
    During the February 1, 2016, meeting, the LPAC recommended that 
PHMSA modify the NPRM to (1) provide a 5-year implementation period for 
existing pipelines and a 1-year implementation period for new pipelines 
and (2) clarify that the expanded use of leak detection systems is not 
applicable to offshore gathering pipelines.
3. PHMSA Response
    PHMSA notes that commenters asserting PHMSA lacks the authority to 
require leak detection systems because it did not first conduct a study 
of these systems are incorrect. PHMSA did perform a leak detection 
study (``Leak Detection Study--DTPH56-11-D000001'' \45\), as required 
by section 8 of the 2011 Pipeline Safety Act, and submitted this study 
to Congress on December 31, 2012. The study examined what methods and 
measures operators were using as leak detection systems and the 
limitations of those methods and measures. The study noted that ``due 
to the vast mileage of pipelines throughout the Nation, it is important 
that dependable leak detection systems are used to promptly identify 
when a leak has occurred so that appropriate response actions are 
initiated quickly. The swiftness of these actions can help reduce the 
consequences of accidents or incidents to the public, environment, and 
property.'' The study also noted that ``incidents described as leaks 
can also have reported large release volumes.'' Based on the results of 
the study, and due to pipeline accidents such as those near Marshall, 
MI, and Salt Lake City, UT, which the study referenced, PHMSA concluded 
that operators need to have an adequate means for identifying leaks to 
better protect the public, property, and the environment. PHMSA 
continues to foster leak detection technology improvements through 
research and development projects, and PHMSA is also considering 
pursuing rupture detection metrics in another rulemaking.
---------------------------------------------------------------------------

    \45\ Kiefner & Associates, Inc.: ``Leak Detection Study,'' Final 
Report No. 12-173, DTPH56-11-D-000001, December 10, 2012. http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Press%20Release%20Files/Leak%20Detection%20Study.pdf.
---------------------------------------------------------------------------

    Recognizing that leak detection technology can be unreliable does 
not imply that monitoring and leak detection are without value. The 
value of lost product, negative impacts to the environment, loss of 
pipeline functionality, spill remediation costs, and public perception 
all impact decisions regarding the implementation of leak detection 
systems. It is difficult to assign costs to many of these items. PHMSA 
expects that the implementation of leak detection systems on non-HCA 
pipelines will accelerate leak detection, lead to faster response and 
spill containment, and reduce damages from hazardous liquid releases.
    Given this information, PHMSA is finalizing a rule that requires 
all new and existing lines, except for gathering lines not subject to 
IM, regulated rural gathering lines, and offshore lines, to implement 
leak detection systems. Since all lines within HCAs are already subject 
to this requirement, the final rule affects pipelines outside of HCAs.

[[Page 52285]]

    Commenters and LPAC members made persuasive arguments regarding the 
technical challenges that exist for implementing leak detection systems 
on offshore gathering lines due to the complex network of gathering 
lines coming from offshore platforms and tremendous fluctuations in 
flow controlled directly by production platforms. Further, commenters 
had concerns that there was not adequate justification for leak 
detection requirements on regulated rural gathering lines due to the 
lack of incident history. PHMSA did not receive any data or comments 
that contradicted these assertions; therefore, PHMSA is not extending 
leak detection requirements to offshore gathering lines or regulated 
rural gathering lines at this time. However, PHMSA does note that the 
LPAC had no objections to extending this requirement to regulated rural 
gathering lines and found the provision to be a cost-effective, 
practicable, and technically feasible provision. Further, during the 
12866 meeting between OIRA and API on December 12, 2016, API presented 
data stating that operators agree with PHMSA's assumptions regarding 
the use of leak detection systems on non-HCA pipelines. As such, PHMSA 
may consider extending leak detection requirements to these lines in 
the future.
    PHMSA considered input from the comments and from the LPAC in 
setting compliance periods of 1 year for all new lines, and 5 years for 
all existing lines. Regarding concerns about compliance periods for 
pipelines under construction, PHMSA considers any line that becomes 
operational after the publication of this rule to be a new line and 
will have 1 year to comply. PHMSA will consider pipelines that are 
already operational before the publication of this rule as existing 
lines, and those will have 5 years to comply. PHMSA determined that the 
specified timelines are reasonable and practicable given that many 
operators already implement leak detection systems on their entire 
network across both HCA and non-HCA miles, and because many operators 
are constructing and designing new lines with leak detection system 
capabilities. Further, PHMSA assumes that the cost of extending 
existing capabilities to non-HCA miles is minimal for systems already 
equipped with SCADA sensors (see the RIA for details).
    Certain commenters questioned the methods of leak detection that 
PHMSA would require to comply with this provision. PHMSA notes that 
negative pressure wave monitoring, real-time transient modelling, or 
other external systems are not necessarily required to comply with the 
rule. The costs of using or installing these leak detection system 
components were not explicitly analyzed in the RIA; however, operators 
may voluntarily choose to use these components, as well as any others, 
to comply with the leak detection requirements of the rule.
    PHMSA received several comments regarding leak detection system 
performance criteria, valve spacing requirements, and automatic 
shutdown capability, which were topics listed in the ANPRM. Due to the 
complexity of these topics and the need for further study and public 
comment, PHMSA is pursuing these topics in a separate rulemaking.\46\
---------------------------------------------------------------------------

    \46\ ``Pipeline Safety: Amendments to Parts 192 and 195 to 
Require Valve Installation and Minimum Rupture Detection 
Standards,'' RIN: 2137-AF06.
---------------------------------------------------------------------------

G. Increased Use of ILI Tools in HCAs

1. PHMSA's Proposal
    PHMSA proposed to require that all hazardous liquid pipelines in 
HCAs and areas that could affect an HCA be made capable of 
accommodating ILI tools within 20 years, unless the basic construction 
of a pipeline will not accommodate the passage of such a device. The 
current requirements for the passage of ILI devices in hazardous liquid 
pipelines are prescribed in Sec.  195.120, which require that new and 
replaced pipelines be designed to accommodate in-line inspection tools. 
Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the 
requirements for the passage of ILI tools to be extended to existing 
hazardous liquid pipeline facilities, provided the basic construction 
of those facilities can be modified to permit the use of smart pigs.
2. Summary of Public Comment
    Trade organizations expressed concern that the NPRM would inhibit 
operators from exercising their expert judgement in selecting an 
assessment method and would be overly burdensome. API-AOPL and other 
industry representatives requested that PHMSA not adopt this proposal 
because it would require pipelines to incur extensive costs due to age, 
design, and location of the pipelines, without demonstrating 
commensurate benefits. They also requested that PHMSA remove the 
requirement to petition for an exemption under Sec.  190.9 and instead 
continue to allow operators to exercise their expertise and engineering 
judgment in using the most effective and efficient methods of 
evaluating the integrity of their facilities with prior notification to 
OPS.
    The IPAA and the American Gas Association (AGA) requested that 
PHMSA review current studies or conduct an original study to determine 
if ILI is appropriate to monitor pipeline corrosion given the current 
state of technology. The AGA also requested that PHMSA provide 
additional information on what the term ``basic construction'' meant in 
the exemption from the ILI-capable requirement.
    Conversely, citizen groups and individuals recommended that 
operators use ILI more broadly. An organization representing public 
safety and other commenters expressed concern with the length of the 
20-year implementation period and the multiple exemptions such as where 
the pipe is constructed in such a way that an ILI device cannot be 
accommodated. Some of these commenters recommended instead that: (1) 
PHMSA significantly reduce the timing of accommodating ILI devices, 
perhaps to 5 years; (2) PHMSA require all new pipelines constructed in 
HCAs to accommodate ILI devices immediately; (3) PHMSA reexamine and 
tighten proposed exemptions; and (4) PHMSA establish standards for ILI 
tools, including the detection of stress corrosion cracking. 
Congresswoman Capps suggested that PHMSA could establish a shorter time 
frame of 5 years with an extension possible upon request with 
sufficient evidence for need and a provided plan of action to meet the 
standard. The PST recommended that operators integrate close interval 
survey results into ILI device findings.
    Other groups commented on the tools used for inspection, the 
compliance periods, and accountability. The Environmental Defense 
Center requested that PHMSA require other inspection tools and methods, 
such as hydrostatic pressure testing, where operators detect certain 
types of anomalies and when these technologies can provide additional 
information regarding the condition and vulnerabilities of a pipeline 
system. The Alliance for Great Lakes et al. recommended that PHMSA 
develop a framework that assigns different compliance periods for 
pipelines based on factors such as age, leak history, corrosion, 
environmental circumstances that could affect the pipeline, and other 
aspects such as those typically reviewed in IM studies. Finally, 
California Assembly Member Das Williams requested that operators be 
required to submit ILI data to PHMSA for review and verification.
    The NTSB recommended that PHMSA require owners/operators to develop 
comprehensive implementation plans with transparent progress reporting 
of

[[Page 52286]]

intermediate milestones to best ensure operators modify existing 
pipelines to accommodate the passage of ILI devices within the 20-year 
time limit. The NTSB also recommended that operators modify all newly 
identified HCA segments to accommodate an internal inspection tool 
according to an accelerated schedule, but not more than 5 years after 
an operator identifies the HCA.
    During the February 1, 2016, meeting, the LPAC recommended that 
PHMSA adopt the proposed 20-year implementation period as feasible and 
cost-effective. In a separate vote, the LPAC reached a tie on a 10-year 
implementation period, which resulted in a failed motion. The LPAC also 
recommended that Sec.  195.452(n) be modified to allow an operator to 
file a petition that ILI tools cannot be accommodated when the operator 
determines it would abandon or shut down a pipeline as a result of the 
cost to comply.
3. PHMSA Response
    PHMSA carefully considered input from commenters and the LPAC in 
finalizing this rule, which requires that all HCA pipelines whose basic 
construction would accommodate ILI tools be modified to permit the use 
of ILI tools within 20 years. Examples of ``basic construction'' that 
an operator may be able to show would not accommodate ILI tools include 
short length, small diameter, diameter changes, low operating pressure, 
low-volume flow, location, sharp bends, and terrain. PHMSA shares the 
interest of commenters who requested expeditious upgrades to the 
pipeline network to accommodate ILI tools. PHMSA maintains that ILI 
tools are generally more effective than other methods at detecting 
integrity issues. ILI tools take advantage of state-of-the-art 
technological developments and allow operators to identify anomalies 
and prioritize anomalies without interrupting services. ILI tools also 
provide a higher level of detail than is possible using other testing 
tools such as hydrotesting, which allow operators to determine whether 
a required safety margin is met (i.e., pass/fail) but do not provide 
information about the existence of anomalies that could deteriorate 
over time between tests. PHMSA notes that the existing regulation 
already requires new pipelines to be capable of accommodating ILI 
tools, as certain commenters requested. Data from operators' pipeline 
annual reports suggest that the vast majority of pipeline miles are 
currently assessed using ILI tools. The mileage not assessed using 
these tools is likely to consist of pipeline segments, such as small 
diameter pipes, where ILI is impracticable using the current 
technologies. Providing sufficient time for ILI tool accommodation 
projects allows the industry to prioritize these projects based on age 
or other factors, including the risk factors identified by the Alliance 
for the Great Lakes in their comments; it also reduces the mileage of 
pipeline potentially needing to be replaced before they have reached 
their operational life. PHMSA determined that a 20-year timeline 
strikes the appropriate balance between the need to make upgrades as 
soon as possible to enable more effective integrity assessment 
technologies, with the costs and operational practicalities of making 
those changes. Given that a preponderance of HCA pipelines can already 
accommodate ILI tools, exceptions available for specific pipeline 
designs, operational benefits of ILI over other assessment methods, the 
continued aging of unpiggable lines, and the 20-year compliance 
deadline that will further reduce remaining mileage of old pre-ILI 
pipeline, PHMSA determined that the final rule requirement to make 
existing HCA pipelines able to accommodate ILI tools is unlikely to 
impact any amount of the hazardous liquid pipeline infrastructure.\47\ 
Accordingly, PHMSA does not estimate any cost for this requirement.
---------------------------------------------------------------------------

    \47\ In the RIA, PHMSA estimates that over 98 percent of 
pipelines for which ILI is applicable likely are already able to 
accommodate ILI tools. Given the factors listed here, PHMSA assumes 
that essentially all HCA lines for which ILII is practicable are 
currently, or will be within the next 20 years, piggable. Further 
details are in the RIA for this rulemaking.
---------------------------------------------------------------------------

    PHMSA will consider modifying its annual report form to have 
hazardous liquid pipeline operators report data on what percentages of 
their lines are piggable. In response to commenters who sought more 
immediate implementation, PHMSA notes that inability to use ILI on a 
pipeline segment does not mean that an operator has not assessed the 
pipeline; the regulation requires that these pipelines be assessed 
using alternative approaches, with hydrotesting being the most common 
alternative. Data reviewed by PHMSA indicates that less than 1 percent 
of HCA pipeline mileage is assessed using direct assessment methods. 
Comments about seismicity considerations are addressed in the next 
section.
    In response to commenters who requested a specific deadline for 
making lines in newly identified HCAs capable of accommodating ILI 
tools, PHMSA notes that operators will have until the end of the 20-
year implementation period to make lines piggable. Operators who newly 
identify HCAs in years 16-20 of the implementation period and after the 
20-year implementation period will have 5 years from the date of the 
HCA identification to make lines in those areas piggable.

H. Clarifying Other Requirements

1. PHMSA's Proposal
    PHMSA also proposed several other clarifying changes to the 
regulations that were intended to improve compliance. First, PHMSA 
proposed to revise paragraph (b)(1) of Sec.  195.452 to better 
harmonize the current regulations. The existing Sec.  195.452(b)(2) 
requires that segments of new pipelines that could affect HCAs be 
identified before the pipeline begins operations and Sec.  
195.452(d)(1) requires that baseline assessments for covered segments 
of new pipelines be completed by the date the pipeline begins 
operation. However, Sec.  195.452(b)(1) does not require an operator to 
draft its IM program for a new pipeline until 1 year after the pipeline 
begins operation. Improved consistency would be beneficial, as the 
identification of could affect segments and the performance of baseline 
assessments are elements of the written IM program. PHMSA proposed to 
amend the table in (b)(1) to resolve this inconsistency by eliminating 
the 1-year compliance deadline for Category 3 pipelines. An operator of 
a new pipeline would be required to develop its written IM program 
before the pipeline begins operation.
    PHMSA proposed to add additional specificity to Sec.  195.452(g) by 
establishing several pipeline attributes that must be included in IM 
information analyses and to explicitly require that operators integrate 
analyzed information to help ensure they are properly evaluating 
interacting threats. PHMSA also proposed that operators explicitly 
consider any spatial relationships among anomalous information.
    PHMSA also proposed that operators verify their segment 
identification annually by determining whether factors considered in 
their analysis have changed. The change that PHMSA proposed would not 
require that operators automatically re-perform their segment analyses. 
Rather, it would require operators to identify the factors considered 
in their original analyses, determine whether those factors have 
changed, and consider whether any such change would be likely to affect 
the results of the original segment

[[Page 52287]]

identification. If so, the operator would be required to perform a new 
segment analysis to validate or change the endpoints of the segments 
affected by the change.
    PHMSA also proposed to add an explicit reference clarifying that 
the IM requirements apply to portions of pipeline facilities other than 
line pipe. Unlike integrity assessments for line pipe, Sec.  195.452 
does not include explicit deadlines for completing the analyses of 
other facilities within the definition of ``pipeline'' or for 
implementing actions in response to those analyses. While most 
operators correctly treat any component that product moves through in 
areas that could affect HCAs as subject to IM, PHMSA has reason to 
believe that some operators have not completed analyses of their non-
pipe facilities such as pump stations and breakout tanks and have not 
implemented appropriate protective and mitigative measures.
    Section 29 of the 2011 Pipeline Safety Act states that ``[i]n 
identifying and evaluating all potential threats to each pipeline 
segment pursuant to parts 192 and 195 of title 49, Code of Federal 
Regulations, an operator of a pipeline facility shall consider the 
seismicity of the area.'' While seismicity is already mentioned at 
several points in the IM program guidance provided in Appendix C of 
part 195, PHMSA proposed to further comply with Congress's directive by 
including an explicit reference to seismicity in the list of risk 
factors that must be considered in establishing assessment schedules 
(Sec.  195.452(e)), performing information analyses (Sec.  195.452(g)), 
and implementing preventive and mitigative measures (Sec.  195.452(i)) 
under the IM requirements.
2. Summary of Public Comment
    Trade organizations commented primarily on the implementation 
period for PHMSA's clarifications on data integration and the 
attributes and information required. Other trade associations joined 
API-AOPL in requesting a 5-year implementation schedule for integrating 
these specific attributes, including populating data into information 
systems and validating the quality of the data process. The AGA 
recommended that PHMSA focus on the analysis of information and 
attributes rather than their integration.
    Trade organizations also requested flexibility in developing the 
attributes and information required in data analysis. The AGA requested 
that operators independently develop the list of information and 
attributes to be included in data analysis. They also commented that 
there is no current regulatory requirement for an operator of hazardous 
liquid or natural gas pipelines to maintain or utilize a GIS.
    Finally, trade organizations expressed concern with changes to the 
baseline assessment of newly constructed pipelines. API-AOPL requested 
that PHMSA clarify that hydrostatic testing is an acceptable method of 
meeting this requirement for new construction.
    During the February 1, 2016, meeting, the LPAC recommended that 
PHMSA modify the NPRM to require data integration to begin in year one, 
with all attributes completed within 3 years.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters. As 
discussed at the LPAC meeting, integrating data is a key element and 
concept of continuous improvement and IM. The requirement that 
operators perform data integration has long been a part of IM program 
requirements. The attributes that PHMSA proposed in the NPRM were 
factors operators should have already been considering when assessing 
risk to their pipelines--PHMSA is merely codifying them to better 
ensure all operators are utilizing them. PHMSA understands that the 
need for some operators to enhance their data systems to fit these 
specific attributes will take some time and effort. Because of this, 
PHMSA agrees with the LPAC that operators should be given a maximum of 
3 years to fully comply and integrate all the proposed attributes into 
their data integration systems, with implementation beginning once the 
rule is published. However, this implementation period does not mean 
operators should lapse in what they are currently required to perform 
under Sec.  195.452(g). PHMSA expects operators to add the attributes 
issued in this final rule to their current data integration systems and 
efforts. While PHMSA is sympathetic to allowing operators more 
flexibility with the attributes that should be considered for data 
integration, experience has shown that PHMSA needs to prescribe a 
common baseline set of attributes for operators to assess.
    PHMSA agrees with commenters who believe hydrostatic testing is an 
acceptable baseline assessment method for newly constructed pipelines 
and is incorporating that option into this final rule. As operators are 
required to conduct hydrostatic tests on all newly constructed 
pipelines prior to operation, and PHMSA allows operators to use 
hydrostatic testing for subsequent assessments, PHMSA has determined 
this could eliminate additional duplicative baseline assessments and 
reduce operator burden.

V. PIPES Act of 2016

    On June 22, 2016, the President signed the PIPES Act of 2016, 
Public Law 114-183, containing Sections 14 and 25, ``Safety Data 
Sheets'' and ``Requirements for Certain Hazardous Liquid Pipeline 
Facilities,'' respectively. The language in both Section 14 and Section 
25 is self-executing, with Section 25 specifically amending the 
Pipeline Safety Act at 49 U.S.C. 60109 by adding new paragraphs (g) 
through (g)(4). To allow the timely implementation of these sections of 
the PIPES Act of 2016 and to help ensure regulatory certainty, PHMSA 
has determined that good cause exists for finding that notice and 
comment on these provisions is impracticable and contrary to the public 
interest and is subsequently incorporating them into this final rule.
    Section 14 of the PIPES Act of 2016 requires owners and operators 
of hazardous liquid pipeline facilities, following accidents involving 
pipeline facilities that result in hazardous liquid spills and within 6 
hours of a telephonic or electronic notice of the accident to the 
National Response Center, to provide safety data sheets on any spilled 
hazardous liquid to the designated Federal On-Scene Coordinator and 
appropriate State and local emergency responders. PHMSA has 
incorporated this requirement in a new Sec.  195.65 under the reporting 
requirements of Subpart B.
    Section 25 of the PIPES Act of 2016 applies to operators of any 
underwater hazardous liquid pipeline facility located in an HCA that is 
not an offshore pipeline facility and any portion of which is located 
at depths greater than 150 feet under the surface of the water. 
Operators of these facilities, notwithstanding any pipeline integrity 
management program or integrity assessment schedule otherwise required 
by the Secretary, must ensure that pipeline integrity assessments using 
internal inspection technology appropriate for the pipeline's integrity 
threats are completed not less often than once every 12 months; and 
using pipeline route surveys, depth of cover surveys, pressure tests, 
ECDA, or other technology that the operator demonstrates can further 
the understanding of the condition of the pipeline facility, ensure 
that pipeline integrity assessments are completed on a schedule based 
on the risk that the pipeline facility poses to the HCA in which the 
pipeline facility is located. PHMSA has incorporated these

[[Page 52288]]

requirements in a new Sec.  195.454 as an addition to the pipeline 
integrity management requirements under subpart F.

VI. Section-by-Section Analysis

Sec.  195.1 Which pipelines are covered by this part?

    Section 195.1(a) lists the pipelines that are subject to the 
requirements in 49 CFR part 195, including gathering lines that cross 
waterways used for commercial navigation as well as certain onshore 
gathering lines (i.e., those that are in a non-rural area, that meet 
the definition of a regulated onshore gathering line, or that are in an 
inlet of the Gulf of Mexico). PHMSA has determined it needs additional 
information about unregulated gathering lines to fulfill its statutory 
obligations, and it has determined it needs additional information 
about gravity lines to determine whether any safety regulations need to 
be extended to these lines as well. Accordingly, this final rule 
extends the reporting requirements in subpart B of part 195 to all 
gravity and gathering lines (whether regulated, unregulated, onshore, 
or offshore).

Sec.  195.2 Definitions

    Section 195.2 provides definitions for various terms used 
throughout part 195. On August 10, 2007, PHMSA published a policy 
statement and request for comment on the transportation of ethanol, 
ethanol blends, and other biofuels by pipeline (72 FR 45002). PHMSA 
noted in the policy statement that the demand for biofuels was 
projected to increase in the future because of several Federal energy 
policy initiatives, and that the predominant modes for transporting 
such commodities (i.e., truck, rail, or barge) would expand over time 
to include greater use of pipelines. PHMSA also stated that ethanol and 
other biofuels are substances that ``may pose an unreasonable risk to 
life or property'' within the meaning of 49 U.S.C. 60101(a)(4)(B) and 
accordingly these materials constitute ``hazardous liquids'' for 
purposes of the pipeline safety laws and regulations.
    PHMSA is modifying the definition of ``hazardous liquid'' in Sec.  
195.2 to conform with 49 U.S.C. 60101(a)(4)(B) and clarify that the 
transportation of biofuel by pipeline is subject to the requirements of 
49 CFR part 195.

Section 195.3 What documents are incorporated by reference partly or 
wholly in this part?

    The incorporation by reference of NACE SP0102 and API RP 1130 was 
previously approved by the Director of the Federal Register and is not 
changed by this rule.

Section 195.13 What requirements apply to pipelines transporting 
hazardous liquids by gravity?

    Section 195.13 is added to subject gravity lines to the same 
annual, accident, and safety-related condition reporting requirements 
in subpart B of part 195 as other hazardous liquid pipelines.

Section 195.15 What reporting requirements apply to reporting-
regulated-only gathering lines?

    Section 195.15 is added to subject otherwise unregulated rural 
gathering lines and certain offshore lines in State waters to the 
annual, accident and safety-related condition reporting requirements in 
subpart B of part 195 as other hazardous liquid pipelines.

Section 195.65 Safety Data Sheets

    Section 195.65 contains the requirements for providing safety data 
sheets on spilled hazardous liquids following accidents. In accordance 
with Section 14 of the PIPES Act of 2016, PHMSA is requiring owners and 
operators of hazardous liquid pipeline facilities, following accidents 
that result in hazardous liquid spills, to provide safety data sheets 
on those spilled hazardous liquids to the designated Federal On-Scene 
Coordinator and appropriate State and local emergency responders within 
6 hours of a telephonic or electronic notice of the accident to the 
National Response Center. This is a self-executing provision from the 
PIPES Act of 2016 that PHMSA is incorporating into subpart B of the 
hazardous liquid pipeline safety regulations.

Section 195.120 Passage of Internal Inspection Devices

    Section 195.120 contains the requirements for accommodating the 
passage of internal inspection devices in the design and construction 
of new or replaced pipelines. PHMSA has decided that, in the absence of 
an emergency, or where the basic construction makes that accommodation 
impracticable, a pipeline should be designed and constructed to permit 
the use of ILIs. Accordingly, this final rule repeals the provisions in 
the regulation that allow operators to petition the Administrator for a 
finding that the ILI compatibility requirement should not apply as a 
result of construction-related time constraints and problems. The other 
provisions in Sec.  195.120 are re-organized without altering the 
existing substantive requirements.

Section 195.134 Leak Detection

    Section 195.134 contains the design requirements for computational 
pipeline monitoring leak detection systems. The final rule restructures 
the existing requirements into paragraphs (a) and (c) and adds a new 
provision in paragraphs (b) and (d) to ensure that all newly 
constructed, covered pipelines are designed to include leak detection 
systems based upon standards in section 4.2 of API 1130 or other 
applicable design criteria in the standard.

Section 195.401 General Requirements

    Section 195.401 prescribes general requirements for the operation 
and maintenance of hazardous liquid pipelines. PHMSA is modifying the 
pipeline repair requirements in Sec.  195.401(b). PHMSA is retaining, 
without change, the requirements in paragraphs (b)(1) for non-IM 
repairs and (b)(2) for IM repairs. A new paragraph (b)(3) is added, 
however, to clearly require operators to consider the risk to people, 
property, and the environment in prioritizing the remediation of any 
condition that could adversely affect the safe operation of a pipeline 
system, no matter whether those conditions are in HCAs or non-HCAs.

Section 195.414 Inspections of Pipelines in Areas Affected by Extreme 
Weather and Natural Disasters

    Extreme weather and natural disasters can affect the safe operation 
of a pipeline. Accordingly, this final rule establishes a new Sec.  
195.414 that requires operators to perform inspections after these 
events and to take appropriate remedial actions.

Section 195.416 Pipeline Assessments

    Periodic assessments, particularly with ILI tools, provide critical 
information about the condition of a pipeline, but are only currently 
required under IM requirements in Sec. Sec.  195.450 through 195.452. 
PHMSA has determined that operators should be required to have the 
information needed to promptly detect and remediate conditions that 
could affect the safe operation of pipelines in all areas. Accordingly, 
the final rule establishes a new Sec.  195.416 that requires operators 
to perform an assessment, at least once every 10 years, of onshore 
pipelines that can accommodate inline inspection tools and that are not 
already subject to the IM requirements. This assessment must be 
performed for the range of relevant threats to the pipeline segment 
using an appropriate ILI tool(s) and

[[Page 52289]]

account for uncertainties in reported results. Operators must use a 
method capable of assessing seam integrity and corrosion and 
deformation anomalies when assessing LF-ERW pipe, lap-welded pipe, or 
pipe with a seam factor of less than 1.0. In lieu of performing an ILI 
assessment on their lines, operators can perform the assessment by 
using a pressure test, external corrosion direct assessment, or other 
technology (subject to prior notification, method being able to assess 
the threat, and ``no objection'' by PHMSA) that can be demonstrated as 
providing an equivalent understanding of the pipe's condition.
    The regulation also requires that the results of these assessments 
be reviewed by a person qualified to determine if any conditions exist 
that could affect the safe operation of a pipeline; that such 
determinations be made promptly, but no later than 180 days after the 
assessment; that any unsafe conditions be remediated in accordance with 
the repair requirements in Sec.  195.401(b)(1); and that all relevant 
information about the pipeline be considering in complying with the 
requirements of Sec.  195.416. Consistent with the requirements in the 
revised Sec.  195.452(h)(2) regarding the discovery of condition, in 
cases where the information necessary to make determination about 
pipeline threats cannot be obtained within 180 days following the date 
of inspection, pipeline operators must notify PHMSA and provide an 
expected date when adequate information will become available.

Section 195.444 Leak Detection

    Section 195.444 contains the operation and maintenance requirements 
for Computational Pipeline Monitoring leak detection systems. PHMSA is 
amending the PSR so that all covered hazardous liquid pipelines have a 
leak detection system. Therefore, the final rule reorganizes the 
existing requirements of the regulation into paragraphs (a) and (c), 
and adds a new general provision in paragraph (b) that requires 
operators to have leak detection systems on all covered pipelines and 
to consider certain factors in determining what kind of system is 
necessary to protect the public, property, and the environment.

Section 195.452 Pipeline Integrity Management in High Consequence Areas

    Section 195.452 contains the IM requirements for hazardous liquid 
pipelines that could affect a HCA in the event of a leak or failure. 
The final rule clarifies the applicability of the deadlines in 
paragraph (b) for the development of a written program for new 
pipelines and low-stress pipelines in rural areas. The rule also makes 
the following amendments to paragraphs (c) through (o):
     Paragraph (c)(1)(i)(A) is amended to ensure that operators 
consider uncertainty in tool tolerance in reviewing the results of ILI 
assessments. The paragraph is also amended to be more consistent with 
paragraphs at Sec.  195.416 by stating that pipeline segments with 
identified or probable risks or threats related to cracks (such as at 
pipe body and weld seams) based on the risk factors specified in 
paragraph (e), an operator must use an ILI tool or tools capable of 
detecting crack anomalies.
     Paragraph (d) is amended to eliminate obsolete deadlines 
for performing baseline assessments and to clarify the requirements for 
newly identified HCAs. The deletion of these previous compliance dates 
does not change or delete any associated recordkeeping requirements or 
implement any new recordkeeping requirements. Operators should retain 
the records they have used to show compliance regarding the baseline 
assessment deadlines.
     Paragraph (e)(1)(vii) is amended to include local 
environmental factors, including seismicity, that might affect pipeline 
integrity.
     Paragraph (g) is amended to prescribe certain data points 
and criteria that operators must consider in performing the information 
analysis required to evaluate periodically the integrity of covered 
pipeline segments.
     Paragraph (h)(2) is amended to require that in those 
situations where an operator must obtain adequate information within 
180 days after an integrity assessment to determine whether an 
anomalous condition could present a potential integrity threat of the 
pipeline but the operator believes it is impracticable to obtain 
sufficient information within that period, the operator must notify 
PHMSA and provide an expected date when adequate information will 
become available.
     Paragraph (j) is amended to establish a new provision for 
verifying the risk factors used in identifying covered segments on at 
least an annual basis, not to exceed 15 months.
     A new paragraph (n) is added to require that all pipelines 
in areas that could affect an HCA be made capable of accommodating ILI 
tools within 20 years, unless, subject to a petition and PHMSA 
approval, the basic construction of a pipeline will not permit that 
accommodation, the existence of an emergency renders such an 
accommodation impracticable, or the operator determines it would 
abandon or shut down a pipeline as a result of the cost to comply with 
the requirement of this section. Paragraph (n) requires that pipelines 
in newly identified HCAs after the 20-year period be made capable of 
accommodating ILIs within 5 years of the date of identification or 
before the performance of the baseline assessment, whichever is sooner.
     Paragraph (o) is added to allow operators additional time 
to integrate the additional information and attributes that PHMSA has 
added to the information analysis required under paragraph (g)(1).
     Finally, an explicit reference to seismicity is added to 
factors that must be considered in establishing assessment schedules 
under paragraph (e), for performing information analyses under 
paragraph (g), and for implementing preventive and mitigative measures 
under paragraph (i).

Section 195.454 Integrity Assessments for Certain Underwater Hazardous 
Liquid Pipeline Facilities Located in HCAs

    Section 195.454 contains additional assessment requirements for 
operators of any underwater hazardous liquid pipeline facility located 
in an HCA that is not an offshore pipeline facility and any portion of 
which is located at depths greater than 150 feet under the surface of 
the water. In accordance with section 25 of the PIPES Act of 2016, 
PHMSA is requiring these operators to ensure that they complete 
pipeline integrity assessments not less often than once every 12 months 
using internal inspection technology appropriate for the integrity 
threats to the pipeline and complete pipeline integrity assessments 
using pipeline route surveys, depth of cover surveys, pressure tests, 
external corrosion direct assessment, or other technology that the 
operator demonstrates can further the understanding of the condition of 
the pipeline facility, on a schedule based on the risk that the 
pipeline facility poses to the HCA in which the pipeline facility is 
located. This is a self-executing provision from the PIPES Act of 2016 
that PHMSA is incorporating into subpart F of the hazardous liquid 
pipeline safety regulations.

VII. Regulatory Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of the Federal 
Pipeline Safety

[[Page 52290]]

Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes the Secretary 
of Transportation to issue regulations governing design, installation, 
inspection, emergency plans and procedures, testing, construction, 
extension, operation, replacement, and maintenance of pipeline 
facilities, as delegated to the PHMSA Administrator under 49 CFR 1.97.
    PHMSA is revising the ``Authority'' entry for part 195 to include a 
citation to a provision of the Mineral Leasing Act (MLA), specifically, 
30 U.S.C. 185(w)(3). Section 185(w)(3) provides that ``[p]eriodically, 
but at least once a year, the Secretary of the Department of 
Transportation shall cause the examination of all pipelines and 
associated facilities on Federal lands and shall cause the prompt 
reporting of any potential leaks or safety problems.'' The Secretary 
has delegated this responsibility to PHMSA (49 CFR 1.97). PHMSA has 
traditionally complied with Sec.  185(w)(3) through the issuance of its 
pipeline safety regulations, which require annual examinations and 
prompt reporting for all or most of the pipelines they cover. PHMSA is 
making this change to be consistent with and make clear its long-
standing position that the agency complies with the MLA through the 
issuance of pipeline safety regulations.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    This final rule is a significant regulatory action under Section 
3(f) of Executive Order 12866 (58 FR 51735), and therefore was reviewed 
by the Office of Management and Budget. This final rule is 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.
    In the regulatory analysis, PHMSA discusses the alternatives to the 
amended requirements and, where possible, provides estimates of the 
benefits and costs for specific regulatory requirements by individual 
requirement areas. The regulatory analysis provides PHMSA's best 
estimate of the impact of the final rule requirements. As shown in the 
table below, PHMSA estimated the total annual costs of the rule at 
$19.5 million using a 3 percent discount rate and $21.4 million using a 
7 percent discount rate.
    Due to data limitations, PHMSA evaluated the benefits of the final 
rule qualitatively. Overall, the rule will provide direct benefits 
through avoiding damages from hazardous pipeline incidents that may be 
prevented through earlier detection of threats to pipeline integrity 
from corrosion or following extreme weather events, and through 
enhancing the ability of PHMSA and pipeline operators to evaluate 
risks. As context, operator-reported data for hazardous liquid 
incidents that occurred between 2010 and 2017 show reported average 
annual damages of $91.6 million for pipelines outside HCAs and $265.8 
million for pipelines inside HCAs, or about $815 and $3,222 per mile of 
hazardous liquid pipeline, respectively. These damages are only a 
fraction of the total social costs of hazardous liquid releases but 
indicate the potential magnitude of benefits derived from preventing 
pipeline failures. 
---------------------------------------------------------------------------

    \48\ Numbers in this table may not sum due to rounding.

                         Annualized Costs and Benefits by Requirement Area (2017$) \48\
----------------------------------------------------------------------------------------------------------------
                                                    Annual costs \1\
  Final rule requirement area   --------------------------------------------------------         Benefits
                                      3% Discount rate            7% Discount rate
----------------------------------------------------------------------------------------------------------------
1. Reporting requirements for    $5,000....................  $5,000....................  Better risk
 gravity lines.                                                                           understanding and
                                                                                          management.\2\
2. Reporting requirements for    $75,000...................  $76,000...................  Better risk
 gathering lines.                                                                         understanding and
                                                                                          management.\3\
3. Inspections of pipelines in   Minimal...................  Minimal...................  Additional clarity and
 areas affected by extreme                                                                certainty for pipeline
 weather events \4\.                                                                      operators.
4. Assessments of onshore        $6,467,000................  $6,467,000................  Avoided incidents and
 pipelines that are not already                                                           damages through
 covered under the IM program                                                             detection of safety
 using ILI every 10 years 5 6.                                                            conditions.\7\
5. IM repair criteria \8\......  $0........................  $0........................  $0.
6. LDSs on pipelines located     $8,652,000................  $10,508,000...............  Reduced damages through
 outside HCAs \6\.                                                                        earlier detection and
                                                                                          response.\9\
7. Increased use of ILI tools    Minimal...................  Minimal...................  Improved detection of
 \10\.                                                                                    pipeline flaws.\10\
8. Clarify certain IM plan       $4,269,000................  $4,343,000................  Reduced damages through
 requirements..                                                                           prevention and earlier
                                                                                          detection and
                                                                                          response.\11\
                                --------------------------------------------------------------------------------
    Total......................  $19,468,000...............  $21,399,000...............  Reduced damages from
                                                                                          avoiding and/or
                                                                                          mitigating hazardous
                                                                                          liquid releases.
----------------------------------------------------------------------------------------------------------------
\1\ Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in
  individual sections of the document. One-time costs are annualized over a 10-year period using discount rates
  of 3 percent and 7 percent.
\2\ Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow
  pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of
  this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated
  gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
  101 gallons per year to generate benefits that equal the costs.
\3\ The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated
  gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
  1,493 gallons per year to generate benefits that equal the costs.
\4\ To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting
  inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not
  reflected in this analysis.
\5\ PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not
  currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios:
  (1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a
  scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two
  scenarios are $0 and $12.9 million, respectively.
\6\ Excludes gathering lines.
\7\ Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to
  prevent 12 incidents for benefits to equate costs.
\8\ PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or
  benefits.

[[Page 52291]]

 
\9\ As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an
  average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of
  approximately $382,179, not including additional damages and costs that are excluded or underreported in the
  incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents.
\10\ Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the
  extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be
  minimal due to baseline prevalence of ILI-capable pipelines in all areas.
\11\ The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids
  cannot be quantified but could vary in frequency and size depending on the types of failures that are averted.
  Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected
  to enhance an operator's ability to identify and address risk. The societal costs associated with incidents
  involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates
  for this requirement are equivalent to the average damages from less than three such incidents. This is
  relative to an annual average of 161 incidents in HCAs between 2010 and 2017.

    Overall, factors such as increased safety, public confidence that 
all pipelines are regulated, quicker discovery of leaks and mitigation 
of environmental damages, and better risk management are expected to 
yield benefits that exceed or otherwise justify the costs. A copy of 
the final RIA has been placed in the docket. Pursuant to the 
Congressional Review Act (5 U.S.C. 801 et seq., the Office of 
Information and Regulatory Affairs designated this rule as not a 
``major rule,'' as defined by 5 U.S.C. 804(2).

C. Executive Order 13771: Reducing Regulation and Controlling 
Regulatory Costs

    The final rule is an Executive Order 13771 regulatory action. 
Details on the estimated costs of this final rule can be found in the 
rule's economic analysis.

D. Executive Order 13132: Federalism

    This final rule has been analyzed in accordance with the principles 
and criteria contained in Executive Order 13132 (``Federalism''). This 
final rule does not adopt any regulation that has substantial direct 
effects 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. It does not adopt any regulation that 
imposes substantial direct compliance costs on state and local 
governments. Therefore, the consultation and funding requirements of 
Executive Order 13132 do not apply.

E. Regulatory Flexibility Act

    The Regulatory Flexibility Act of 1980 (Pub. L. 96-354) (RFA) 
establishes ``as a principle of regulatory issuance that agencies shall 
endeavor, consistent with the objectives of the rule and of applicable 
statutes, to fit regulatory and informational requirements to the scale 
of the businesses, organizations, and governmental jurisdictions 
subject to regulation. To achieve this principle, agencies are required 
to solicit and consider flexible regulatory proposals and to explain 
the rationale for their actions to assure that such proposals are given 
serious consideration.''
    The RFA covers a wide range of small entities, including small 
businesses, not-for-profit organizations, and small governmental 
jurisdictions. Agencies must perform a review to determine whether a 
rule will have a significant economic impact on a substantial number of 
small entities. If the agency determines that it will, the agency must 
prepare a regulatory flexibility analysis as described in the RFA.
    However, if an agency determines that a rule is not expected to 
have a significant economic impact on a substantial number of small 
entities, section 605(b) of the RFA provides that the head of the 
agency may so certify and a regulatory flexibility analysis is not 
required. The certification must include a statement providing the 
factual basis for this determination, and the reasoning should be 
clear.
    PHMSA performed a screening analysis of the economic impact on 
small entities. The screening analysis is available in the docket for 
the rulemaking. PHMSA estimates that compliance costs may exceed 1 
percent of sales for 23 to 31 of the estimated small businesses and may 
exceed 3 percent of sales for 9 to 10 small businesses. The higher 
number of affected small businesses assumes that the operator incurs 
costs for all applicable requirements.
    Given the small number and percentage of small businesses affected, 
the small sales test ratios, and the noted flexibility, PHMSA 
determined that the final rule will not have a significant impact on a 
substantial number of small entities.\49\
---------------------------------------------------------------------------

    \49\ Based on SBA (2013), including criteria developed by other 
agencies.
---------------------------------------------------------------------------

    Therefore, I certify that this action does not have a significant 
economic impact on a substantial number of small entities.

F. National Environmental Policy Act

    PHMSA analyzed this final rule in accordance with section 102(2)(c) 
of the National Environmental Policy Act (42 U.S.C. 4332), the Council 
on Environmental Quality regulations (40 CFR parts 1500 through 1508), 
and DOT Order 5610.1C, and has determined that this action will not 
significantly affect the quality of the human environment. An 
environmental assessment of this rulemaking is available in the docket.

G. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This final rule has been analyzed in accordance with the principles 
and criteria contained in Executive Order 13175 (``Consultation and 
Coordination with Indian Tribal Governments''). Because this final rule 
does not have Tribal implications and does not impose substantial 
direct compliance costs on Indian Tribal governments, the funding and 
consultation requirements of Executive Order 13175 do not apply.

H. 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 the proposals in this rulemaking will impact 
the following information collections:
    ``Transportation of Hazardous Liquids by Pipeline: Recordkeeping 
and Accident Reporting'' identified under Office of Management and 
Budget (OMB) Control Number 2137-0047;
    ``Reporting Safety-Related Conditions on Gas, Hazardous Liquid, and 
Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities'' 
identified under OMB Control Number 2137-0578;
    ``Integrity Management in High Consequence Areas for Operators of 
Hazardous Liquid Pipelines'' identified under OMB Control Number 2137-
0605;
    ``Pipeline Safety: Reporting Requirements for Hazardous Liquid 
Pipeline Operators: Hazardous Liquid Annual Report'' identified under 
OMB Control Number 2137-0614;
    ``National Registry of Pipeline and LNG Operators'' identified 
under OMB Control Number 2137-0627; and
    ``Operator Notifications--Alternate Pressure Testing Method'' 
identified under OMB Control Number 2137-0630.
    PHMSA will submit an information collection revision request to OMB 
for

[[Page 52292]]

approval based on the requirements in this rule. These information 
collections are contained in the Federal Pipeline Safety Regulations, 
49 CFR parts 190-199. 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 burden for the following information collections 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: 08/31/2020.
    Abstract: This information collection covers the collection of 
information from owners and operators of hazardous liquid pipelines. To 
ensure adequate public protection from exposure to potential hazardous 
liquid pipeline failures, PHMSA collects information on reportable 
hazardous liquid pipeline accidents. 49 CFR 195.54 requires hazardous 
liquid operators to file an accident report, as soon as practicable, 
but not later than 30 days after discovery of the accident, on DOT Form 
7000-1 whenever there is a reportable accident the characteristics of 
an operator's pipeline system. The final rule will require operators of 
both gravity lines and gathering lines to be subject to these accident 
reporting requirements. Thus, PHMSA expects an additional 28 HL 
pipeline operators (23 gathering line operators and approximately 5 
gravity line operators) to be added to the reporting community.
    If the frequency of accidents is the same for non-regulated 
gathering lines and gravity lines as it is for transmission lines, 
approximately 4 to 6 percent of these newly regulated operators will 
submit an accident report in any given year. Of the 23 new gathering 
line operators, PHMSA expects 5 accident reports to be filed per year. 
Of the 5 new gravity line operators, PHMSA expects 1 accident report to 
be filed per year. This results in an added burden of 6 new accident 
reports per year at 10 hours per report for a total added burden of 60 
hours for accident reporting.
    The final rule will also amend the Pipeline Safety Regulations 
(PSR) in 49 CFR 195.65 to require all owners and operators of hazardous 
liquid pipeline facilities, following accidents that result in 
hazardous liquid spills, to provide safety data sheets on those spilled 
hazardous liquids to the designated Federal On-Scene Coordinator and 
appropriate State and local emergency responders within 6 hours of a 
telephonic or electronic notice of the accident to the National 
Response Center. PHMSA expects hazardous liquid operators to file 
approximately 406 accident reports per year. This will result in an 
added burden of 406 new notifications per year. PHMSA expects that it 
will take operators 30 minutes to conduct the required task. This will 
result in an added burden of 406 records at .5 hours per record for a 
total added burden of 203 hours for safety data sheet notifications 
recordkeeping.
    This information collection is being revised to account for the 
additional burden that will be incurred because of these new 
provisions.
    Affected Public: Owners and operators of hazardous liquid 
pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 1,644.
    Total Annual Burden Hours: 52,692.
    Frequency of Collection: On occasion.
    2. Title: Reporting Safety-Related Conditions on Gas, Hazardous 
Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas 
Facilities.
    OMB Control Number: 2137-0578.
    Current Expiration Date: 8/31/2022.
    Abstract: 49 U.S.C. 60102 requires each operator of a pipeline 
facility (except master meter operators) to submit to U.S. DOT a 
written report on any safety-related condition that causes or has 
caused a significant change or restriction in the operation of a 
pipeline facility or a condition that is a hazard to life, property or 
the environment.
    This rule will require operators of both gravity lines and 
gathering lines to be subject to safety-related condition reporting. 
While there is no guarantee that each of the newly covered operators 
will incur a safety-related condition, it is a possibility. As a 
result, PHMSA plans to include an additional 28 hazardous liquid 
pipeline operators (23 gathering line operators and approximately 5 
gravity line operators) in this reporting community. PHMSA estimates 
that it takes each operator 6 hours to complete a safety-related 
condition report. The addition of the 28 newly covered operators will 
result in 28 additional responses and an added burden of 168 hours (28 
operators * 6 hours).
    This information collection is being revised to account for the 
additional burden that will be incurred by newly regulated entities. 
Operators currently submitting annual reports will not be otherwise 
impacted by this rule.
    Affected Public: Owners and operators of hazardous liquid 
pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 174.
    Total Annual Burden Hours: 1,044.
    Frequency of Collection: On occasion.
    3. Title: Hazardous Liquid Pipeline Assessment Requirements.
    OMB Control Number: 2137-0605.
    Current Expiration Date: 09/30/2022.
    Abstract: Owners and operators of hazardous liquid pipelines are 
required to have continual assessment and evaluation of pipeline 
integrity through inspection or testing, as well as remedial preventive 
and mitigative actions. Because of this rulemaking action, in cases 
where a determination about pipeline threats has not been obtained 
within 180 days following the date of inspection, pipeline operators 
are required to notify PHMSA in writing and provide an expected date 
when adequate information will become available. PHMSA estimates that 
only 1 percent of repair reports (approx. 74) will require these 
notifications each year. Operators are authorized to send the 
notification, via email, to PHMSA's Information Resources Manager. 
PHMSA estimates that it will take operators 30 minutes to create and 
send each notification resulting in an overall burden increase of 37 
hours annually.
    Hazardous liquid pipeline operators are also required to notify 
PHMSA when they are unable to assess their pipeline via an in-line 
inspection. Operators who choose to use an alternate assessment method 
must demonstrate that their pipeline is not capable of accommodating an 
in-line inspection tool and that the use of an alternative assessment 
method will provide a substantially equivalent understanding of the 
condition of the pipeline. PHMSA estimates that operators will submit 
approximately 10 notifications each year regarding these conditions. 
Further, PHMSA estimates that each notification will take 10 hours, 
which includes the time to assemble the necessary information to 
demonstrate that the pipeline is not capable of accommodating an ILI 
tool and specify that the alternative assessment method will provide a 
substantially equivalent understanding of the pipeline. This will 
result in an annual notification burden of 100 hours.
    The overall annual burden increase for this information collection 
is 84 responses and 137 hours. PHMSA requests the title of this 
information collection, previously ``Integrity Management in High 
Consequence Areas for Operators of Hazardous Liquid Pipelines,'' be 
changes to better align with the requested data.

[[Page 52293]]

    Affected Public: Owners and operators of Hazardous Liquid 
Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 287.
    Total Annual Burden Hours: 325,607.
    Frequency of Collection: Annually.
    4. Title: Pipeline Safety: Reporting Requirements for Hazardous 
Liquid Pipeline Operators: Hazardous Liquid Annual Report.
    OMB Control Number: 2137-0614.
    Current Expiration Date: 01/31/2022.
    Abstract: Owners and operators of hazardous liquid pipelines are 
required to provide PHMSA with safety-related documentation relative to 
the annual operation of their pipeline. The provided information is 
used to compile a national pipeline inventory, identify safety 
problems, and target inspections.
    Due to provisions within this final rule, approximately 5 gravity 
line operators and 23 gathering line operators will be required to 
submit annual reports to PHMSA. PHMSA estimates the burden associated 
with annual reporting activities to be approximately 19 hours per 
report, composed of 12 hours of a compliance officer's time and 7 hours 
of a secretary/administrative assistant's time. The newly regulated 
gravity and gathering line operators will cause an added burden of 28 
new annual reports per year at 19 hours per report for a total added 
burden of 532 hours for annual reporting.
    This information collection is being revised to account for the 
additional burden that will be incurred by the newly affected 
operators. Operators currently submitting annual reports will not be 
otherwise impacted by this rule.
    Affected Public: Owners and operators of hazardous liquid 
pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 475.
    Total Annual Burden Hours: 8,989.
    Frequency of Collection: Annually.
    5. Title: National Registry of Pipeline and LNG Operators.
    OMB Control Number: 2137-0627.
    Current Expiration Date: 04/301/2022.
    Abstract: The National Registry of Pipeline and LNG Operators 
serves as the storehouse for the reporting requirements for an operator 
regulated under or subject to reporting requirements of 49 CFR parts 
191, 192, 193, or 195. The final rule requires operators of both 
gravity lines and gathering lines to be subject to various reporting 
requirements. Thus, approximately 5 gravity line operators and 23 
gathering line operators will be required to register their pipeline 
with the National Pipeline Registry and apply for an Operator 
Identification number (OPID). PHMSA estimates that this activity will 
take 1 hour per operator to register.
    Gravity and gathering line operators will also be required to 
notify PHMSA of certain changes made to their pipeline system when 
applicable. PHMSA estimates that 5 percent (approximately 1) of these 
newly regulated operators will make these notifications each year. 
PHMSA estimates that this activity will take 1 hour per operator.
    This information collection is being revised to account for the 
additional burden (29 responses x 1 hour = 29 hours) that will be 
incurred by the newly regulated operators. Operators currently 
registered will not be otherwise impacted by this rule.
    Affected Public: Natural gas, LNG, and hazardous liquid pipeline 
operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 718.
    Total Annual Burden Hours: 718.
    6. Title: Hazardous Liquid Operator Notifications.
    OMB Control Number: 2137-0630.
    Current Expiration Date: N/A.
    Abstract: The Pipeline Safety regulations contained within 49 CFR 
part 195 require hazardous liquid operators to notify PHMSA in various 
instances. 49 CFR 195.414 requires hazardous liquid operators who are 
unable to inspect their pipeline facilities within 72 hours of an 
extreme weather event to notify the appropriate PHMSA Region Director 
as soon as practicable. PHMSA expects to receive 100 of these 
notifications annually. PHMSA believes it will take operators 
approximately 15 minutes (0.25 hours) to make this notification and 
send it to the Regional Director electronically. PHMSA expects the 
annual burden for this requirement to be 25 hours.
    49 CFR 195.452 requires operators of pipelines that cannot 
accommodate an in-line inspection tool to file a petition in compliance 
with 49 CFR 190.9. PHMSA expects to receive 10 of these notifications 
annually. PHMSA expects that it will take operators 10 hours to provide 
records to demonstrate that their pipeline cannot accommodate an inline 
inspection device for an overall annual burden of 100 hours for this 
notification requirement.
    Affected Public: Owners and operators of hazardous liquid 
pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 110.
    Total Annual Burden Hours: 125.
    Frequency of Collection: Annually.
    Requests for copies of these information collections should be 
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline 
Safety (PHP-30), Pipeline and Hazardous Materials Safety Administration 
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-
0001, Telephone (202) 366-4595.
    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.
    Those desiring to comment on these information collections should 
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 October 31, 2019. Comments 
may also be sent via email to the Office of Management and Budget at 
the following address: oira_submissions@omb.eop.gov. OMB is required to 
make a decision concerning the collection of information requirements 
contained in this final rule between 30 and 60 days after publication 
of this document in the Federal Register. Therefore, a comment to OMB 
is best assured of having its full effect if received within 30 days of 
publication.

I. Privacy Act Statement

    Anyone is able to search the electronic form of all comments 
received into any of our dockets by the name of the individual 
submitting the comment (or signing the comment, if submitted on behalf 
of an association, business, labor union, etc.). You may review DOT's 
complete Privacy Act Statement in the Federal Register published on 
April 11, 2000 (65 FR 19477), or at http://www.regulations.gov.

[[Page 52294]]

J. Regulation Identifier Number (RIN)

    A regulation identifier number (RIN) is assigned to each regulatory 
action listed in the Unified Agenda of Federal Regulations. The 
Regulatory Information Service Center publishes the Unified Agenda in 
April and October of each year. The RIN contained in the heading of 
this document may be used to cross-reference this action with the 
Unified Agenda.

List of Subjects in 49 CFR Part 195

    Incorporation by reference, Integrity management, Pipeline safety.

    In consideration of the foregoing, PHMSA is amending 49 CFR part 
195 as follows:

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
1. Revise the authority citation for part 195 to read as follows:

    Authority:  30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq., 
and 49 CFR 1.97.

0
2. Amend Sec.  195.1 by adding paragraph (a)(5) and revising paragraphs 
(b)(2) and (b)(4) to read as follows:

Sec.  195.1  Which pipelines are covered by this part?

    (a) * * *
    (5) For purposes of the reporting requirements in subpart B of this 
part, any gathering line not already covered under paragraphs (a)(1), 
(2), (3) or (4) of this section.
    (b) * * *
    (2) Except for the reporting requirements of subpart B of this 
part, see Sec.  195.13, transportation of a hazardous liquid through a 
pipeline by gravity.
* * * * *
    (4) Except for the reporting requirements of subpart B of this 
part, see Sec.  195.15, transportation of petroleum through an onshore 
rural gathering line that does not meet the definition of a ``regulated 
rural gathering line'' as provided in Sec.  195.11. This exception does 
not apply to gathering lines in the inlets of the Gulf of Mexico 
subject to Sec.  195.413.
* * * * *

0
3. Amend Sec.  195.2 by revising the definition for ``Hazardous 
liquid'' to read as follows:

Sec.  195.2  Definitions.

* * * * *
    Hazardous liquid means petroleum, petroleum products, anhydrous 
ammonia, and ethanol or other non-petroleum fuel, including biofuel, 
which is flammable, toxic, or would be harmful to the environment if 
released in significant quantities.
* * * * *

Sec.  195.3   [Amended]

0
4. In Sec.  195.3, amend paragraph (g)(3) by removing ``Sec.  195.591'' 
and adding ``Sec. Sec.  195.120 and 195.591'' in its place.

0
5. Add Sec.  195.13 to subpart A to read as follows:

Sec.  195.13  What requirements apply to pipelines transporting 
hazardous liquids by gravity?

    (a) Scope. Pipelines transporting hazardous liquids by gravity must 
comply with the reporting requirements of subpart B of this part.
    (b) Implementation period--(1) Annual reporting. Comply with the 
annual reporting requirements in subpart B of this part by March 31, 
2021.
    (2) Accident and safety-related reporting. Comply with the accident 
and safety-related condition reporting requirements in subpart B of 
this part by January 1, 2021.
    (c) Exceptions. (1) This section does not apply to the 
transportation of a hazardous liquid in a gravity line that meets the 
definition of a low-stress pipeline, travels no farther than 1 mile 
from a facility boundary, and does not cross any waterways used for 
commercial navigation.
    (2) The reporting requirements in Sec. Sec.  195.52, 195.61, and 
195.65 do not apply to the transportation of a hazardous liquid in a 
gravity line.
    (3) The drug and alcohol testing requirements in part 199 of this 
subchapter do not apply to the transportation of a hazardous liquid in 
a gravity line.

0
6. Add Sec.  195.15 to subpart A to read as follows:

Sec.  195.15  What requirements apply to reporting-regulated-only 
gathering lines?

    (a) Scope. Gathering lines that do not otherwise meet the 
definition of a regulated rural gathering line in Sec.  195.11 and any 
gathering line not already covered under Sec.  195.1(a)(1), (2), (3) or 
(4) must comply with the reporting requirements of subpart B of this 
part.
    (b) Implementation period--(1) Annual reporting. Operators must 
comply with the annual reporting requirements in subpart B of this part 
by March 31, 2021.
    (2) Accident and safety-related condition reporting. Operators must 
comply with the accident and safety-related condition reporting 
requirements in subpart B of this part by January 1, 2021.
    (c) Exceptions. (1) This section does not apply to those gathering 
lines that are otherwise excepted under Sec.  195.1(b)(3), (7), (8), 
(9), or (10).
    (2) The reporting requirements in Sec. Sec.  195.52, 195.61, and 
195.65 do not apply to the transportation of a hazardous liquid in a 
gathering line that is specified in paragraph (a) of this section.
    (3) The drug and alcohol testing requirements in part 199 of this 
subchapter do not apply to the transportation of a hazardous liquid in 
a gathering line that is specified in paragraph (a) of this section.

0
7. Add Sec.  195.65 to subpart B to read as follows:

Sec.  195.65  Safety data sheets.

    (a) Each owner or operator of a hazardous liquid pipeline facility, 
following an accident involving a pipeline facility that results in a 
hazardous liquid spill, must provide safety data sheets on any spilled 
hazardous liquid to the designated Federal On-Scene Coordinator and 
appropriate State and local emergency responders within 6 hours of a 
telephonic or electronic notice of the accident to the National 
Response Center.
    (b) Definitions. In this section:
    (1) Federal On-Scene Coordinator. The term ``Federal On-Scene 
Coordinator'' has the meaning given such term in section 311(a) of the 
Federal Water Pollution Control Act (33 U.S.C. 1321(a)).
    (2) National Response Center. The term ``National Response Center'' 
means the center described under 40 CFR 300.125(a).
    (3) Safety data sheet. The term ``safety data sheet'' means a 
safety data sheet required under 29 CFR 1910.1200.

0
8. Revise Sec.  195.120 to read as follows:

Sec.  195.120  Passage of internal inspection devices.

    (a) General. Except as provided in paragraphs (b) and (c) of this 
section, each new pipeline and each main line section of a pipeline 
where the line pipe, valve, fitting or other line component is replaced 
must be designed and constructed to accommodate the passage of 
instrumented internal inspection devices in accordance with NACE SP0102 
(incorporated by reference, see Sec.  195.3).
    (b) Exceptions. This section does not apply to:
    (1) Manifolds;
    (2) Station piping such as at pump stations, meter stations, or 
pressure reducing stations;

[[Page 52295]]

    (3) Piping associated with tank farms and other storage facilities;
    (4) Cross-overs;
    (5) Pipe for which an instrumented internal inspection device is 
not commercially available; and
    (6) Offshore pipelines, other than lines 10 inches (254 
millimeters) or greater in nominal diameter, that transport liquids to 
onshore facilities.
    (c) Impracticability. An operator may file a petition under Sec.  
190.9 for a finding that the requirements in paragraph (a) of this 
section should not be applied to a pipeline for reasons of 
impracticability.
    (d) Emergencies. An operator need not comply with paragraph (a) of 
this section in constructing a new or replacement segment of a pipeline 
in an emergency. Within 30 days after discovering the emergency, the 
operator must file a petition under Sec.  190.9 for a finding that 
requiring the design and construction of the new or replacement 
pipeline segment to accommodate passage of instrumented internal 
inspection devices would be impracticable as a result of the emergency. 
If PHMSA denies the petition, within 1 year after the date of the 
notice of the denial, the operator must modify the new or replacement 
pipeline segment to allow passage of instrumented internal inspection 
devices.

0
9. Revise Sec.  195.134 to read as follows:

Sec.  195.134  Leak detection.

    (a) Scope. This section applies to each hazardous liquid pipeline 
transporting liquid in single phase (without gas in the liquid).
    (b) General. (1) For each pipeline constructed prior to October 1, 
2019. Each pipeline must have a system for detecting leaks that 
complies with the requirements in Sec.  195.444 by October 1, 2024.
    (2) For each pipeline constructed on or after October 1, 2019. Each 
pipeline must have a system for detecting leaks that complies with the 
requirements in Sec.  195.444 by October 1, 2020.
    (c) CPM leak detection systems. A new computational pipeline 
monitoring (CPM) leak detection system or replaced component of an 
existing CPM system must be designed in accordance with the 
requirements in section 4.2 of API RP 1130 (incorporated by reference, 
see Sec.  195.3) and any other applicable design criteria in that 
standard.
    (d) Exception. The requirements of paragraph (b) of this section do 
not apply to offshore gathering or regulated rural gathering lines.

0
10. In Sec.  195.401, add paragraph (b)(3) to read as follows.

Sec.  195.401  General requirements.

* * * * *
    (b) * * *
    (3) Prioritizing repairs. An operator must consider the risk to 
people, property, and the environment in prioritizing the correction of 
any conditions referenced in paragraphs (b)(1) and (2) of this section.
* * * * *

0
11. Add Sec.  195.414 to read as follows:

Sec.  195.414  Inspections of pipelines in areas affected by extreme 
weather and natural disasters.

    (a) General. Following an extreme weather event or natural disaster 
that has the likelihood of damage to infrastructure by the scouring or 
movement of the soil surrounding the pipeline, such as a named tropical 
storm or hurricane; a flood that exceeds the river, shoreline, or creek 
high-water banks in the area of the pipeline; a landslide in the area 
of the pipeline; or an earthquake in the area of the pipeline, an 
operator must inspect all potentially affected pipeline facilities to 
detect conditions that could adversely affect the safe operation of 
that pipeline.
    (b) Inspection method. An operator must consider the nature of the 
event and the physical characteristics, operating conditions, location, 
and prior history of the affected pipeline in determining the 
appropriate method for performing the initial inspection to determine 
the extent of any damage and the need for the additional assessments 
required under paragraph (a) of this section.
    (c) Time period. The inspection required under paragraph (a) of 
this section must commence within 72 hours after the cessation of the 
event, defined as the point in time when the affected area can be 
safely accessed by the personnel and equipment required to perform the 
inspection as determined under paragraph (b) of this section. In the 
event that the operator is unable to commence the inspection due to the 
unavailability of personnel or equipment, the operator must notify the 
appropriate PHMSA Region Director as soon as practicable.
    (d) Remedial action. An operator must take prompt and appropriate 
remedial action to ensure the safe operation of a pipeline based on the 
information obtained as a result of performing the inspection required 
under paragraph (a) of this section. Such actions might include, but 
are not limited to:
    (1) Reducing the operating pressure or shutting down the pipeline;
    (2) Modifying, repairing, or replacing any damaged pipeline 
facilities;
    (3) Preventing, mitigating, or eliminating any unsafe conditions in 
the pipeline right-of-way;
    (4) Performing additional patrols, surveys, tests, or inspections;
    (5) Implementing emergency response activities with Federal, State, 
or local personnel; and
    (6) Notifying affected communities of the steps that can be taken 
to ensure public safety.

0
12. Add Sec.  195.416 to read as follows:

Sec.  195.416  Pipeline assessments.

    (a) Scope. This section applies to onshore line pipe that can 
accommodate inspection by means of in-line inspection tools and is not 
subject to the integrity management requirements in Sec.  195.452.
    (b) General. An operator must perform an initial assessment of each 
of its pipeline segments by October 1, 2029, and perform periodic 
assessments of its pipeline segments at least once every 10 calendar 
years from the year of the prior assessment or as otherwise necessary 
to ensure public safety or the protection of the environment.
    (c) Method. Except as specified in paragraph (d) of this section, 
an operator must perform the integrity assessment for the range of 
relevant threats to the pipeline segment by the use of an appropriate 
in-line inspection tool(s). When performing an assessment using an in-
line inspection tool, an operator must comply with Sec.  195.591. An 
operator must explicitly consider uncertainties in reported results 
(including tool tolerance, anomaly findings, and unity chart plots or 
other equivalent methods for determining uncertainties) in identifying 
anomalies. If this is impracticable based on operational limits, 
including operating pressure, low flow, and pipeline length or 
availability of in-line inspection tool technology for the pipe 
diameter, then the operator must perform the assessment using the 
appropriate method(s) in paragraphs (c)(1), (2), or (3) of this section 
for the range of relevant threats being assessed. The methods an 
operator selects to assess low-frequency electric resistance welded 
pipe, pipe with a seam factor less than 1.0 as defined in Sec.  
195.106(e) or lap-welded pipe susceptible to longitudinal seam failure 
must be capable of assessing seam integrity, cracking, and of detecting 
corrosion and deformation anomalies. The following alternative 
assessment methods may be used as specified in this paragraph:
    (1) A pressure test conducted in accordance with subpart E of this 
part;

[[Page 52296]]

    (2) External corrosion direct assessment in accordance with Sec.  
195.588; or
    (3) Other technology in accordance with paragraph (d).
    (d) Other technology. Operators may elect to use other technologies 
if the operator can demonstrate the technology can provide an 
equivalent understanding of the condition of the line pipe for threat 
being assessed. An operator choosing this option must notify the Office 
of Pipeline Safety (OPS) 90 days before conducting the assessment by:
    (1) Sending the notification, along with the information required 
to demonstrate compliance with this paragraph, to the Information 
Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous 
Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, 
DC 20590; or
    (2) Sending the notification, along with the information required 
to demonstrate compliance with this paragraph, to the Information 
Resources Manager by facsimile to (202) 366-7128.
    (3) Prior to conducting the ``other technology'' assessments, the 
operator must receive a notice of ``no objection'' from the PHMSA 
Information Services Manager or Designee.
    (e) Data analysis. A person qualified by knowledge, training, and 
experience must analyze the data obtained from an assessment performed 
under paragraph (b) of this section to determine if a condition could 
adversely affect the safe operation of the pipeline. Operators must 
consider uncertainties in any reported results (including tool 
tolerance) as part of that analysis.
    (f) Discovery of condition. For purposes of Sec.  195.401(b)(1), 
discovery of a condition occurs when an operator has adequate 
information to determine that a condition presenting a potential threat 
to the integrity of the pipeline exists. An operator must promptly, but 
no later than 180 days after an assessment, obtain sufficient 
information about a condition to make that determination required under 
paragraph (e) of this section, unless the operator can demonstrate the 
180-day interval is impracticable. If the operator believes that 180 
days are impracticable to make a determination about a condition found 
during an assessment, the pipeline operator must notify PHMSA and 
provide an expected date when adequate information will become 
available. This notification must be made in accordance with Sec.  
195.452 (m).
    (g) Remediation. An operator must comply with the requirements in 
Sec.  195.401 if a condition that could adversely affect the safe 
operation of a pipeline is discovered in complying with paragraphs (e) 
and (f) of this section.
    (h) Consideration of information. An operator must consider all 
relevant information about a pipeline in complying with the 
requirements in paragraphs (a) through (g) of this section.

0
13. Revise Sec.  195.444 to read as follows:

Sec.  195.444  Leak detection.

    (a) Scope. Except for offshore gathering and regulated rural 
gathering pipelines, this section applies to all hazardous liquid 
pipelines transporting liquid in single phase (without gas in the 
liquid).
    (b) General. A pipeline must have an effective system for detecting 
leaks in accordance with Sec. Sec.  195.134 or 195.452, as appropriate. 
An operator must evaluate the capability of its leak detection system 
to protect the public, property, and the environment and modify it as 
necessary to do so. At a minimum, an operator's evaluation must 
consider the following factors--length and size of the pipeline, type 
of product carried, the swiftness of leak detection, location of 
nearest response personnel, and leak history.
    (c) CPM leak detection systems. Each computational pipeline 
monitoring (CPM) leak detection system installed on a hazardous liquid 
pipeline must comply with API RP 1130 (incorporated by reference, see 
Sec.  195.3) in operating, maintaining, testing, record keeping, and 
dispatcher training of the system.

0
14. Amend Sec.  195.452 by:
0
a. Revising paragraphs (a)(3) and (b)(1), the introductory text of 
paragraph (c)(1)(i), paragraphs (c)(1)(i)(A), (d), (e)(1)(vii), and 
(g), the introductory text of paragraph (h)(1), and paragraph (h)(2);
0
b. Amending paragraph (i)(2)(viii) by removing the period at the end of 
the sentence and adding in its place a ``;''.
0
c. Adding paragraph (i)(2)(ix);
0
d. Revising paragraph (j)(2);
0
e. Adding paragraphs (n) and (o).
    The revisions and additions read as follows:

Sec.  195.452  Pipeline integrity management in high consequence areas.

    (a) * * *
    (3) Category 3 includes pipelines constructed or converted after 
May 29, 2001, and low-stress pipelines in rural areas under Sec.  
195.12.
* * * * *
    (b) * * *
    (1) Develop a written integrity management program that addresses 
the risks on each segment of pipeline in the first column of the 
following table no later than the date in the second column:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Category 1................................  March 31, 2002.
Category 2................................  February 18, 2003.
Category 3................................  Date the pipeline begins
                                             operation or as provided in
                                             Sec.   195.12 for low
                                             stress pipelines in rural
                                             areas.
------------------------------------------------------------------------

* * * * *
    (c) * * *
    (1) * * *
    (i) The methods selected to assess the integrity of the line pipe. 
An operator must assess the integrity of the line pipe by in-line 
inspection tool(s) described in paragraph (c)(1)(i)(A) of this section 
for the range of relevant threats to the pipeline segment. If it is 
impracticable based upon the construction of the pipeline (e.g., 
diameter changes, sharp bends, and elbows) or operational limits 
including operating pressure, low flow, pipeline length, or 
availability of in-line inspection tool technology for the pipe 
diameter, then the operator must use the appropriate method(s) in 
paragraphs (c)(1)(i)(B), (C), or (D) of this section for the range of 
relevant threats to the pipeline segment. The methods an operator 
selects to assess low-frequency electric resistance welded pipe, pipe 
with a seam factor less than 1.0 as defined in Sec.  195.106(e) or lap-
welded pipe susceptible to longitudinal seam failure, must be capable 
of assessing seam integrity, cracking, and of detecting corrosion and 
deformation anomalies.
    (A) In-line inspection tool or tools capable of detecting corrosion 
and deformation anomalies including dents, gouges, and grooves. For 
pipeline segments with an identified or probable risk or threat related 
to cracks (such as at pipe body or weld seams) based on the risk 
factors specified in paragraph (e), an operator must use an in-line 
inspection tool or tools capable of detecting crack anomalies. When 
performing an assessment using an in-line inspection tool, an operator 
must comply with Sec.  195.591. An operator using this method must 
explicitly consider uncertainties in reported results (including tool 
tolerance, anomaly findings, and unity chart plots or equivalent for 
determining uncertainties) in identifying anomalies;
* * * * *
    (d) When must operators complete baseline assessments?
    (1) All pipelines. An operator must complete the baseline 
assessment before a new or conversion-to-service pipeline

[[Page 52297]]

begins operation through the development of procedures, identification 
of high consequence areas, and pressure testing of could-affect high 
consequence areas in accordance with Sec.  195.304.
    (2) Newly identified areas. If an operator obtains information 
(whether from the information analysis required under paragraph (g) of 
this section, Census Bureau maps, or any other source) demonstrating 
that the area around a pipeline segment has changed to meet the 
definition of a high consequence area (see Sec.  195.450), that area 
must be incorporated into the operator's baseline assessment plan 
within 1 year from the date that the information is obtained. An 
operator must complete the baseline assessment of any pipeline segment 
that could affect a newly identified high consequence area within 5 
years from the date an operator identifies the area.
* * * * *
    (e) * * *
    (1) * * *
    (vii) Local environmental factors that could affect the pipeline 
(e.g., seismicity, corrosivity of soil, subsidence, climatic);
* * * * *
    (g) What is an information analysis? In periodically evaluating the 
integrity of each pipeline segment (see paragraph (j) of this section), 
an operator must analyze all available information about the integrity 
of its entire pipeline and the consequences of a possible failure along 
the pipeline. Operators must continue to comply with the data 
integration elements specified in Sec.  195.452(g) that were in effect 
on October 1, 2018, until October 1, 2022. Operators must begin to 
integrate all the data elements specified in this section starting 
October 1, 2020, with all attributes integrated by October 1, 2022. 
This analysis must:
    (1) Integrate information and attributes about the pipeline that 
include, but are not limited to:
    (i) Pipe diameter, wall thickness, grade, and seam type;
    (ii) Pipe coating, including girth weld coating;
    (iii) Maximum operating pressure (MOP) and temperature;
    (iv) Endpoints of segments that could affect high consequence areas 
(HCAs);
    (v) Hydrostatic test pressure including any test failures or 
leaks--if known;
    (vi) Location of casings and if shorted;
    (vii) Any in-service ruptures or leaks--including identified 
causes;
    (viii) Data gathered through integrity assessments required under 
this section;
    (ix) Close interval survey (CIS) survey results;
    (x) Depth of cover surveys;
    (xi) Corrosion protection (CP) rectifier readings;
    (xii) CP test point survey readings and locations;
    (xiii) AC/DC and foreign structure interference surveys;
    (xiv) Pipe coating surveys and cathodic protection surveys.
    (xv) Results of examinations of exposed portions of buried 
pipelines (i.e., pipe and pipe coating condition, see Sec.  195.569);
    (xvi) Stress corrosion cracking (SCC) and other cracking (pipe body 
or weld) excavations and findings, including in-situ non-destructive 
examinations and analysis results for failure stress pressures and 
cyclic fatigue crack growth analysis to estimate the remaining life of 
the pipeline;
    (xvii) Aerial photography;
    (xviii) Location of foreign line crossings;
    (xix) Pipe exposures resulting from repairs and encroachments;
    (xx) Seismicity of the area; and
    (xxi) Other pertinent information derived from operations and 
maintenance activities and any additional tests, inspections, surveys, 
patrols, or monitoring required under this part.
    (2) Consider information critical to determining the potential for, 
and preventing, damage due to excavation, including current and planned 
damage prevention activities, and development or planned development 
along the pipeline;
    (3) Consider how a potential failure would affect high consequence 
areas, such as location of a water intake.
    (4) Identify spatial relationships among anomalous information 
(e.g., corrosion coincident with foreign line crossings; evidence of 
pipeline damage where aerial photography shows evidence of 
encroachment). Storing the information in a geographic information 
system (GIS), alone, is not sufficient. An operator must analyze for 
interrelationships among the data.
    (h) * * *
    (1) General requirements. An operator must take prompt action to 
address all anomalous conditions in the pipeline that the operator 
discovers through the integrity assessment or information analysis. In 
addressing all conditions, an operator must evaluate all anomalous 
conditions and remediate those that could reduce a pipeline's 
integrity, as required by this part. An operator must be able to 
demonstrate that the remediation of the condition will ensure that the 
condition is unlikely to pose a threat to the long-term integrity of 
the pipeline. An operator must comply with all other applicable 
requirements in this part in remediating a condition. Each operator 
must, in repairing its pipeline systems, ensure that the repairs are 
made in a safe and timely manner and are made so as to prevent damage 
to persons, property, or the environment. The calculation method(s) 
used for anomaly evaluation must be applicable for the range of 
relevant threats.
* * * * *
    (2) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information to determine that a condition 
presenting a potential threat to the integrity of the pipeline exists. 
An operator must promptly, but no later than 180 days after an 
assessment, obtain sufficient information about a condition to make 
that determination, unless the operator can demonstrate the 180-day 
interval is impracticable. If the operator believes that 180 days are 
impracticable to make a determination about a condition found during an 
assessment, the pipeline operator must notify PHMSA in accordance with 
paragraph (m) of this section and provide an expected date when 
adequate information will become available.
* * * * *
    (i) * * *
    (2) * * *
    (ix) Seismicity of the area.
* * * * *
    (j) * * *
    (2) Verifying covered segments. An operator must verify the risk 
factors used in identifying pipeline segments that could affect a high 
consequence area on at least an annual basis not to exceed 15 months 
(Appendix C of this part provides additional guidance on factors that 
can influence whether a pipeline segment could affect a high 
consequence area). If a change in circumstance indicates that the prior 
consideration of a risk factor is no longer valid or that an operator 
should consider new risk factors, an operator must perform a new 
integrity analysis and evaluation to establish the endpoints of any 
previously identified covered segments. The integrity analysis and 
evaluation must include consideration of the results of any baseline 
and periodic integrity assessments (see paragraphs (b), (c), (d), and 
(e) of this section), information analyses (see paragraph (g) of this 
section), and decisions about remediation and preventive and mitigative 
actions (see paragraphs (h) and (i) of this section). An operator must 
complete the first annual verification

[[Page 52298]]

under this paragraph no later than July 1, 2021.
* * * * *
    (n) Accommodation of instrumented internal inspection devices--
    (1) Scope. This paragraph does not apply to any pipeline facilities 
listed in Sec.  195.120(b).
    (2) General. An operator must ensure that each pipeline is modified 
to accommodate the passage of an instrumented internal inspection 
device by July 2, 2040.
    (3) Newly identified areas. If a pipeline could affect a newly 
identified high consequence area (see paragraph (d)(2) of this section) 
after July 2, 2035, an operator must modify the pipeline to accommodate 
the passage of an instrumented internal inspection device within 5 
years of the date of identification or before performing the baseline 
assessment, whichever is sooner.
    (4) Lack of accommodation. An operator may file a petition under 
Sec.  190.9 of this chapter for a finding that the basic construction 
(i.e., length, diameter, operating pressure, or location) of a pipeline 
cannot be modified to accommodate the passage of an instrumented 
internal inspection device or that the operator determines it would 
abandon or shut-down a pipeline as a result of the cost to comply with 
the requirement of this section.
    (5) Emergencies. An operator may file a petition under Sec.  190.9 
of this chapter for a finding that a pipeline cannot be modified to 
accommodate the passage of an instrumented internal inspection device 
as a result of an emergency. An operator must file such a petition 
within 30 days after discovering the emergency. If the petition is 
denied, the operator must modify the pipeline to allow the passage of 
an instrumented internal inspection device within 1 year after the date 
of the notice of the denial.

0
15. Add Sec.  195.454 to Subpart F to read as follows:

Sec.  195.454  Integrity assessments for certain underwater hazardous 
liquid pipeline facilities located in high consequence areas.

    Notwithstanding any pipeline integrity management program or 
integrity assessment schedule otherwise required under Sec.  195.452, 
each operator of any underwater hazardous liquid pipeline facility 
located in a high consequence area that is not an offshore pipeline 
facility and any portion of which is located at depths greater than 150 
feet under the surface of the water must ensure that:
    (a) Pipeline integrity assessments using internal inspection 
technology appropriate for the integrity threats to the pipeline are 
completed not less often than once every 12 months, and;
    (b) Pipeline integrity assessments using pipeline route surveys, 
depth of cover surveys, pressure tests, external corrosion direct 
assessment, or other technology that the operator demonstrates can 
further the understanding of the condition of the pipeline facility, 
are completed on a schedule based on the risk that the pipeline 
facility poses to the high consequence area in which the pipeline 
facility is located.

    Issued in Washington, DC, on September 17, 2019, under authority 
delegated in 49 CFR part 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2019-20458 Filed 9-30-19; 8:45 am]
BILLING CODE 4910-60-P