
[Federal Register Volume 81, Number 68 (Friday, April 8, 2016)]
[Proposed Rules]
[Pages 20721-20856]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-06382]



[[Page 20721]]

Vol. 81

Friday,

No. 68

April 8, 2016

Part II





Department of Transportation





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 Pipeline and Hazardous Materials Safety Administration





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49 CFR Parts 191 and 192





 Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines; 
Proposed Rule

  Federal Register / Vol. 81 , No. 68 / Friday, April 8, 2016 / 
Proposed Rules  

[[Page 20722]]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191 and 192

[Docket No. PHMSA-2011-0023]
RIN 2137-AE72


Pipeline Safety: Safety of Gas Transmission and Gathering 
Pipelines

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

ACTION: Notice of proposed rulemaking.

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SUMMARY: This Notice of Proposed Rulemaking (NPRM) proposes to revise 
the Pipeline Safety Regulations applicable to the safety of onshore gas 
transmission and gathering pipelines. PHMSA proposes changes to the 
integrity management (IM) requirements and proposes changes to address 
issues related to non-IM requirements. This NPRM also proposes 
modifying the regulation of onshore gas gathering lines.

DATES: Persons interested in submitting written comments on this NPRM 
must do so by June 7, 2016.

ADDRESSES: You may submit comments identified by the docket number 
PHMSA-2011-0023 by any of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
     Fax: 1-202-493-2251.
     Mail: Hand Delivery: U.S. DOT Docket Management System, 
West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., 
Washington, DC 20590-0001 between 9 a.m. and 5 p.m., Monday through 
Friday, except Federal holidays.
    Instructions: If you submit your comments by mail, submit two 
copies. To receive confirmation that PHMSA received your comments, 
include a self-addressed stamped postcard.
    Note: Comments are posted without changes or edits to http://www.regulations.gov, including any personal information provided. There 
is a privacy statement published on http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366-
4571, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue SE., PHP-
30, Washington, DC 20590-0001.

SUPPLEMENTARY INFORMATION:

Outline of This Document

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. Advance Notice of Proposed Rulemaking
    C. National Transportation Safety Board Recommendations
    D. Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011
    E. Summary of Each Topic Under Consideration
    F. Integrity Verification Process Workshop
III. Analysis of Comments on the Advance Notice of Proposed 
Rulemaking
    A. Modifying the Definition of HCA
    B. Strengthening Requirements To Implement Preventive and 
Mitigative Measures for Pipeline Segments in HCAs
    C. Modifying Repair Criteria
    D. Improving Requirements for Collecting, Validating, and 
Integrating Pipeline Data
    E. Making Requirements Related to the Nature and Application of 
Risk Models More Prescriptive
    F. Strengthening Requirements for Applying Knowledge Gained 
Through the IM Program
    G. Strengthening Requirements on the Selection and Use of 
Assessment Methods
    H. Valve Spacing and the Need for Remotely or Automatically 
Controlled Valves
    I. Corrosion Control
    J. Pipe Manufactured Using Longitudinal Weld Seams
    K. Establishing Requirements Applicable to Underground Gas 
Storage
    L. Management of Change
    M. Quality Management Systems (QMS)
    N. Exemption of Facilities Installed Prior to the Regulations
    O. Modifying the Regulation of Gas Gathering Lines
IV. Other Proposals
V. Section-by-Section Analysis
VI. Availability of Standards Incorporated by Reference
VII. Regulatory Analysis and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

    PHMSA believes that the current regulatory requirements applicable 
to gas pipeline systems have increased the level of safety associated 
with the transportation of gas. Still, incidents with significant 
consequences and various causes continue to occur on gas pipeline 
systems. PHMSA has also identified concerns during inspections of gas 
pipeline operator programs that indicate a potential need to clarify 
and enhance some requirements. Based on this experience, this NPRM 
proposes additional safety measures to increase the level of safety for 
those pipelines that are not in HCAs as well as clarifications and 
selected enhancements to integrity management requirements to improve 
safety in HCAs.
    On August 25, 2011, PHMSA published an Advance Notice of Proposed 
Rulemaking (ANPRM) to seek feedback and comments regarding the revision 
of the Pipeline Safety Regulations applicable to the safety of gas 
transmission and gas gathering pipelines. In particular, PHMSA 
requested comments regarding whether integrity management (IM) 
requirements should be changed and whether other issues related to 
system integrity should be addressed by strengthening or expanding non-
IM requirements.
    Subsequent to issuance of the ANPRM, the National Transportation 
Safety Board (NTSB) adopted its report on the San Bruno accident on 
August 30, 2011. The NTSB issued safety recommendations P-11-1 and P-
11-2 and P-11-8 through -20 to PHMSA, and issued safety recommendations 
P-10-2 through -4 to Pacific Gas & Electric (PG&E), among others. 
Several of these NTSB recommendations related directly to the topics 
addressed in the August 25, 2011 ANPRM and have an impact on the 
proposed approach to rulemaking. Also subsequent to issuance of the 
ANPRM, the Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011 (the Act) was enacted on January 3, 2012. Several of the Act's 
statutory requirements related directly to the topics addressed in the 
August 25, 2011 ANPRM and have an impact on the proposed approach to 
rulemaking.
    Congress has authorized Federal regulation of the transportation of 
gas by pipeline in the Pipeline Safety Laws (49 U.S.C. 60101 et seq.), 
a series of statutes that are administered by the DOT, PHMSA. PHMSA has 
used that authority to promulgate comprehensive minimum safety 
standards for the transportation of gas by pipeline.
    Congress established the current framework for regulating pipelines 
transporting gas in the Natural Gas Pipeline Safety Act of 1968, Public 
Law 90-481. That law delegated to DOT the authority to develop, 
prescribe, and enforce minimum Federal safety standards for the 
transportation of gas, including natural gas, flammable gas, or toxic 
or corrosive gas, by pipeline. Congress has since enacted additional 
legislation that is currently codified in the Pipeline Safety Laws, 
including:

    In 1992, Congress required regulations be issued to define the 
term ``gathering line'' and establish safety standards for certain 
``regulated gathering lines,'' Public Law 102-508. In 1996, Congress 
directed that DOT conduct demonstration projects evaluating the 
application of risk management principles to pipeline safety 
regulation, and

[[Page 20723]]

mandated that regulations be issued for the qualification and 
testing of certain pipeline personnel, Public Law 104-304. In 2002, 
Congress required that DOT issue regulations requiring operators of 
gas transmission pipelines to conduct risk analyses and to implement 
IM programs under which pipeline segments in high consequence areas 
(HCA) would be subject to a baseline assessment within 10 years and 
re-assessments at least every seven years, and required that 
standards be issued for assessment of pipelines using direct 
assessment, Public Law 107-355.

B. Summary of the Major Provisions of the Regulatory Action in Question

    PHMSA plans to address several of the topics in the ANPRM in 
separate rulemakings because of the diverse scope and nature of several 
NTSB recommendations and the statutory requirements of the Act that 
were covered in the ANPRM. This proposed rule addresses several IM 
topics, including: Revision of IM repair criteria for pipeline segments 
in HCAs to address cracking defects, non-immediate corrosion metal loss 
anomalies, and other defects; explicitly including functional 
requirements related to the nature and application of risk models 
currently invoked by reference to industry standards; explicitly 
specifying requirements for collecting, validating, and integrating 
pipeline data models currently invoked by reference to industry 
standards; strengthening requirements for applying knowledge gained 
through the IM Program models currently invoked by reference to 
industry standards; strengthening requirements on the selection and use 
of direct assessment methods models by incorporating recently issued 
industry standards by reference; adding requirements for monitoring gas 
quality and mitigating internal corrosion, and adding requirements for 
external corrosion management programs including above ground surveys, 
close interval surveys, and electrical interference surveys; and 
explicitly including requirements for management of change currently 
invoked by reference to industry standards. With respect to non-IM 
requirements, this NPRM proposes: A new ``moderate consequence areas'' 
definition; adding requirements for monitoring gas quality and 
mitigating internal corrosion; adding requirements for external 
corrosion management programs including above ground surveys, close 
interval surveys, and electrical interference surveys; additional 
requirements for management of change, including invoking the 
requirements of ASME/ANSI B31.8S, Section 11; establishing repair 
criteria for pipeline segments located in areas not in an HCA; and 
requirements for verification of maximum allowable operating pressure 
(MAOP) in accordance with new Sec.  192.624 and for verification of 
pipeline material in accordance with new section Sec.  192.607 for 
certain onshore, steel, gas transmission pipelines. This includes 
establishing and documenting MAOP if the pipeline MAOP was established 
in accordance with Sec.  192.619(c) or the pipeline meets other 
criteria indicating a need for establishing MAOP.
    In addition, this NPRM proposes modifying the regulation of onshore 
gas gathering lines. The proposed rulemaking would repeal the exemption 
for reporting requirements for gas gathering line operators and repeal 
the use of API RP 80 for determining regulated onshore gathering lines 
and add a new definition for ``onshore production facility/operation'' 
and a revised definition for ``gathering lines.'' The proposed 
rulemaking would also extend certain part 192 regulatory requirements 
to Type A lines in Class 1 locations for lines 8 inches or greater. 
Requirements that would apply to previously unregulated pipelines 
meeting these criteria would be limited to damage prevention, corrosion 
control (for metallic pipe), public education program, maximum 
allowable operating pressure limits, line markers, and emergency 
planning.
    This NPRM also proposes requirements for additional topics that 
have arisen since issuance of the ANPRM. These include: (1) Requiring 
inspections by onshore pipeline operators of areas affected by an 
extreme weather event such as a hurricane or flood, landslide, an 
earthquake, a natural disaster, or other similar event; (2) revising 
the regulations to allow extension of the IM 7-year reassessment 
interval upon written notice per Section 5 of the Act; (3) adding a 
requirement to report each exceedance of the MAOP that exceeds the 
margin (build-up) allowed for operation of pressure-limiting or control 
devices per Section 23 of the Act; (4) adding requirements to ensure 
consideration of seismicity of the area in identifying and evaluating 
all potential threats per Section 29 of the Act; (5) adding regulations 
to require safety features on launchers and receivers for in-line 
inspection, scraper, and sphere facilities; and (6) incorporating 
consensus standards into the regulations for assessing the physical 
condition of in-service pipelines using in-line inspection, internal 
corrosion direct assessment, and stress corrosion cracking direct 
assessment.
    The overall goal of this proposed rule is to increase the level of 
safety associated with the transportation of gas by proposing 
requirements to address the causes of recent incidents with significant 
consequences, clarify and enhance some existing requirements, and 
address certain statutory mandates of the Act and NTSB 
recommendations.\1\
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    \1\ PHMSA plans to initiative separate rulemaking to address 
other topics included in the ANPRM and that would implement other 
requirements of the Act and NTSB recommendations.
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C. Costs and Benefits

    Consistent with Executive Orders 12866 and 13563, PHMSA has 
prepared an assessment of the benefits and costs of the proposed rule 
as well as reasonable alternatives. PHMSA is publishing the Preliminary 
Regulatory Impact Analysis (PRIA) for this proposed rule simultaneously 
with this document, and it is available in the docket.
    PHMSA estimates the total (15-year) present value of benefits from 
the proposed rule to be approximately $3,234 to $3,738 million \2\ 
using a 7% discount rate ($4,050 to $4,663 million using a 3% discount 
rate) and the present value of costs to be approximately $597 million 
using a 7% discount rate ($711 million using a 3% discount rate). The 
table below summarizes the average annual present value benefits and 
costs by topic area. The majority of benefits reflect cost savings from 
material verification (processes to determine maximum allowable 
operating pressure for segments for which records are inadequate) under 
the proposed rule compared to existing regulations; the range in these 
benefits reflects different effectiveness assumptions for estimating 
safety benefits. Costs reflect primarily integrity verification and 
assessment costs (pressure tests, inline inspection, and direct 
assessments). The proposed gas gathering regulations account for the 
next largest portion of benefits and costs and primarily reflect safety 
provisions and associated risk reductions on previously unregulated 
lines.
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    \2\ Range reflects uncertainty in defect failure rates for Topic 
Area 1.

[[Page 20724]]



                         Summary of Average Annual Present Value Benefits and Costs \1\
                                                [Millions; 2015$]
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                                                                 7% discount rate           3% discount rate
                        Topic area                         -----------------------------------------------------
                                                               Benefits       Costs       Benefits       Costs
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Re-establish MAOP, verify material properties, and           $196.9-$230.5      $17.8   $247.8-$288.6      $22.0
 integrity assessments outside HCAs.......................
Integrity management process clarifications...............            n.e.        2.2            n.e.        1.3
Management of change process improvement..................             1.1        0.7             1.2        0.8
Corrosion control.........................................             5.5        6.3             5.9        7.9
Pipeline inspection following extreme events..............             0.3        0.1             0.3        0.1
MAOP exceedance reports and records verification..........            n.e.        0.2            n.e.        0.2
Launcher/receiver pressure relief.........................             0.4        0.0             0.6        0.0
Gas gathering regulations.................................            11.3       12.6            14.2       15.1
                                                           -----------------------------------------------------
    Total.................................................     215.6-249.2       39.8       270-310.8       47.4
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HCA = high consequence area.
MAOP = maximum allowable operating pressure.
n.e. = not estimated.
\1\ Total over 15-year study period divided by 15. Additional costs to states estimated not to exceed $1.5
  million per year. Range of benefits reflects range in estimated defect failure rates.
\2\ Break even value of benefits, based on the average consequences for incidents in high consequence areas,
  would equate to less than one incident averted over the 15-year study period.

    For the seven percent discount rate scenario, approximately 13 
percent of benefits are due to safety benefits from incidents averted, 
82 percent represent cost savings from MAOP verification in Topic Area 
1, and four percent are attributable to reductions in greenhouse gas 
emissions. (For the three percent discount rate scenario, these 
percentages are approximately 13, 83, and 3 percent, respectively.)

II. Background

A. Detailed Overview

Introduction
    The significant and expected growth in the nation's production and 
use of natural gas is placing unprecedented demands on the nation's 
pipeline system, underscoring the importance of moving this energy 
product safely and efficiently. With changing spatial patterns of 
natural gas production and use and an aging pipeline network, improved 
documentation and data collection are increasingly necessary for the 
industry to make reasoned safety choices and for preserving public 
confidence in its ability to do so. Congress recognized these needs 
when passing the Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011, calling for an examination of a broad range of 
issues pertaining to the safety of the nation's pipeline network, 
including a thorough application of the risk-based integrity 
assessment, repair, and validation system known as ``integrity 
management'' (IM).
    This proposed rulemaking advances the goals established by Congress 
in the 2011 Act, which are consistent with the emerging needs of the 
natural gas pipeline system. This proposed rule also advances an 
important discussion about the need to adapt and expand risk-based 
safety practices in light of changing markets and a growing national 
population whose location choices increasingly encroach on existing 
pipelines. As some severe pipeline accidents have occurred in areas 
outside of high consequence areas (HCA) where the application of IM 
principles is not required, and as gas pipelines continue to experience 
failures from causes that IM was intended to address, this conversation 
is increasingly important.
    This proposed rule strengthens protocols for IM, including 
protocols for inspections and repairs, and improves and streamlines 
information collection to help drive risk-based identification of the 
areas with the greatest safety deficiencies. Further, this proposed 
rule establishes requirements to periodically assess and extend aspects 
of IM to pipeline segments in locations where the surrounding 
population is expected to potentially be at risk from an incident. Even 
though these segments are not within currently defined HCAs, they could 
be located in areas with significant populations where incidents could 
have serious consequences. This change would facilitate prompt 
identification and remediation of potentially hazardous defects and 
anomalies while still allowing operators to make risk-based decisions 
on where to allocate their maintenance and repair resources.
Natural Gas Infrastructure Overview
    The U.S. natural gas pipeline network is designed to transport 
natural gas to and from most locations in the lower 48 States. 
Approximately two-thirds of the lower 48 States depend almost entirely 
on the interstate transmission pipeline system for their supplies of 
natural gas.\3\ To envision the scope of the nation's natural gas 
pipeline infrastructure, it is best to consider it in three 
interconnected parts that together transport natural gas from the 
production field, where gas is extracted from underground, to its end 
users, where the gas is used as an energy fuel or chemical feedstock. 
These three parts are referred to as gathering, transmission, and 
distribution systems. Because this proposed rule applies only to gas 
gathering and transmission lines, this document will not discuss 
natural gas distribution infrastructure and its associated issues. 
Currently, there are over 11,000 miles of onshore gas gathering 
pipelines and 297,814 miles of onshore gas transmission pipelines 
throughout the U.S.\4\
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    \3\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' 
Quadrennial Energy Review Report: Energy Transmission, Storage, and 
Distribution Infrastructure, p. NG-28, April 2015.
    \4\ US DOT Pipeline and Hazardous Materials Safety 
Administration Data as of 9/25/2015.
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    Gas gathering lines are pipelines used to transport natural gas 
from production sites to central collection points, which are often gas 
treatment plants where pipeline-quality gas is separated from petroleum 
liquids and various impurities. Historically, these lines were of 
smaller diameters than gas transmission lines and operated at lower 
pressures. However, due to changing demand factors, some gathering 
lines are being constructed with diameters equal to or larger than 
typical transmission lines and are being operated at much higher 
pressures.
    Transmission pipelines primarily transport natural gas from gas 
treatment

[[Page 20725]]

plants and gathering systems to bulk customers, local distribution 
networks, and storage facilities. Transmission pipelines are typically 
made of steel and can range in size from several inches to several feet 
in diameter. They can operate over a wide range of pressures, from 
relatively low (200 pounds per square inch) to over 1,500 pounds per 
square inch gage (psig). They can operate within the geographic 
boundaries of a single State, or span hundreds of miles, crossing one 
or more State lines.
Regulatory History
    PHMSA and its State partners regulate pipeline safety for 
jurisdictional \5\ gas gathering, transmission, and distribution 
systems under minimum Federal safety standards authorized by statute 
\6\ and codified in the Pipeline Safety Regulations at 49 CFR parts 
190-199.
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    \5\ Typically, onshore pipelines involved in the 
``transportation of gas''--see 49 CFR 192.1 and 192.3 for detailed 
applicability.
    \6\ Title 49, United States Code, Subtitle VIII, Pipelines, 
Sections 60101, et. seq.
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    Federal regulation of gas pipeline safety began in 1968 with the 
creation of the Office of Pipeline Safety and their subsequent issuance 
of interim minimum Federal safety standards for gas pipeline facilities 
and the transportation of natural and other gas in accordance with the 
Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). These Federal 
safety standards were upgraded several times over the following decades 
to address different aspects of natural gas transportation by pipeline, 
including construction standards, pipeline materials, design standards, 
class locations, corrosion control, and maximum allowable operating 
pressure (MAOP).
    These original Pipeline Safety Regulations were not designed with 
risk-based regulations 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 that there were no minimum standards or 
requirements.
    In response to a hazardous liquid incident in Bellingham, WA, in 
1999 that killed 3 people and a gas transmission incident in Carlsbad, 
NM, in 2000 that killed 12, IM regulations for gas transmission 
pipelines were finalized in 2004.\7\ The primary goal of the 2004 IM 
regulations was to provide a structure to operators for focusing their 
resources on improving pipeline integrity in the areas where a failure 
would have the greatest impact on public safety. Further objectives 
included accelerating the integrity assessment of pipelines in HCAs, 
improving IM systems within companies, improving the government's 
ability to review the adequacy of integrity programs and plans, thus 
providing increased public assurance in pipeline safety.
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    \7\ [68 FR 69778, Dec. 15, 2003] 49 CFR part 192 [Docket No. 
RSPA-00-7666; Amendment 192-95] Pipeline Safety: Pipeline Integrity 
Management in High Consequence Areas (Gas Transmission Pipelines).
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    The IM regulations specify how pipeline operators must conduct 
comprehensive analyses to identify, prioritize, assess, evaluate, 
repair, and validate the integrity of gas transmission pipelines in 
HCAs, which are typically areas where population is highly 
concentrated. Currently, approximately 7 percent of onshore gas 
transmission pipeline mileage is located in HCAs. PHMSA and state 
inspectors review operators' written IM programs and associated records 
to verify that the operators have used all available information about 
their pipelines to assess risks and take appropriate actions to 
mitigate those risks.
    Since the implementation of the IM regulations more than 10 years 
ago, many factors have changed. Most importantly, sweeping changes in 
the natural gas industry have caused significant shifts in supply and 
demand, and the nation's relatively safe but aging pipeline network 
faces increased pressures from these changes as well as from the 
increased exposure caused by a growing and geographically dispersing 
population. 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 outdated construction methods or materials. Some severe 
pipeline accidents have occurred in areas outside HCAs where the 
application of IM principles is not required. Gas pipelines continue to 
experience failures from causes that IM was intended to address, such 
as corrosion, and the measures currently in use have not always been 
effective in identifying and preventing these causes of pipeline 
damage.
    There is a pressing need for an improved strategy to protect the 
safety and integrity of the nation's pipeline system. Following a 
significant pipeline incident in 2010 at San Bruno, CA, in which 8 
people died and more than 50 people were injured, Congress, the 
National Transportation Safety Board (NTSB), and the Government 
Accountability Office (GAO) charged PHMSA with improving IM. Comments 
from a 2011 advanced notice of proposed rulemaking (ANPRM) suggested 
there were many common-sense improvements that could be made to IM, as 
well as a clear need to extend certain IM provisions to pipelines not 
now covered by the IM regulations. A large portion of the transmission 
pipeline industry has voluntarily committed to extending certain IM 
provisions to non-HCA pipe, which clearly underscores the common 
understanding of the need for this strategy.
    Through this proposed rule, PHMSA is taking action to deliver a 
comprehensive strategy to improve gas transmission pipeline safety and 
reliability, through both immediate improvements to IM and a long-range 
review of risk management and information needs, while also accounting 
for a changing landscape and a changing population.
Supply Changes
    The U.S. natural gas industry has undergone changes of 
unprecedented magnitude and pace, increasing production by 33 percent 
between 2005 and 2013, from 19.5 trillion cubic feet per year to 25.7 
trillion cubic feet per year.\8\ Driving these changes has been a shift 
towards the production of ``unconventional'' natural gas supplies using 
improved technology to extract gas from low permeability shales. The 
increased use of directional drilling and improvements to a long-
existing industrial technique--hydraulic fracturing, which began as an 
experiment in 1947--made the recovery of unconventional natural gas 
easier and economically viable. This shift in production has decreased 
prices and spurred tremendous increases in the use of natural gas.
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    \8\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' 
Quadrennial Energy Review Report: Energy Transmission, Storage, and 
Distribution Infrastructure, p. NG-2, April 2015.
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    While conventional natural gas production in the U.S. has fallen 
over the past decade by about 14 billion cubic feet per day, overall 
natural gas production has grown due to increased unconventional shale 
gas production. In 2004, unconventional shale gas accounted for about 5 
percent of the total natural gas production in the U.S. Since then, 
unconventional shale gas

[[Page 20726]]

production has increased more than tenfold from 2.7 Bcf/d to about 35.0 
Bcf/d in 2014 \9\ and now accounts for about half of overall gas 
production in the U.S.\10\
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    \9\ Id., at NG-7.
    \10\ Id.
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    This increase in unconventional natural gas production shifted 
production away from traditional gas-rich regions towards onshore shale 
gas regions. In 2004, the Gulf of Mexico produced about 20 percent of 
the nation's natural gas supply, but by2013, that number had fallen to 
5 percent. During that same time, Pennsylvania's share of production 
grew from 1 percent to 13 percent. An analysis conducted by the 
Department of Energy's (DOE) Office of Energy Policy and Systems 
Analysis projects that the most significant increases in production 
through 2030 will occur in the Marcellus and Utica Basins in the 
Appalachian Basin,\11\ which will continue to fuel growth in natural 
gas production from current levels of 66.5 Bcf/d to more than 93.5 Bcf/
d.\12\
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    \11\ Id., at NG-6.
    \12\ Id.
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Demand Changes
    The recent increase in domestic natural gas production has led to 
decreased gas price volatility and lower average prices.\13\ In 2004, 
the outlook for natural gas production and demand growth was weak. 
Monthly average spot prices at Henry Hub \14\ were high, fluctuating 
between $4 per million British thermal units (Btu) and $7 per million 
Btu. Prices rose above $11 per million Btu for several months in both 
2005 and 2008.\15\ Since 2008, after production shifted to onshore 
unconventional shale resources, and price volatility fell away 
following the Great Recession, natural gas has traded between about $2 
per million Btu and $5 per million Btu.\16\
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    \13\ Id., at NG-11.
    \14\ Henry Hub is a Louisiana natural gas distribution hub where 
conventional Gulf of Mexico natural gas can be directed to gas 
transmission lines running to different parts of the country. Gas 
bought and sold at the Henry hub serves as the national benchmark 
for U.S. natural gas prices. (Id., at NG-29, NG-30).
    \15\ Energy Information Administration, Natural Gas Spot and 
Futures Prices, http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm, 
retrieved 14 October 2015.
    \16\ Id., at NG-11.
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    These historically low prices for this commodity are fueling 
tremendous consumption growth and changes in markets and spatial 
patterns of consumption. A shift towards natural gas-fueled electric 
power generation is helping to serve the needs of the nation's growing 
population while helping reduce greenhouse gas emissions, and American 
industries are taking advantage of cheap energy by investing in onshore 
production capacity, while also exploring economic opportunities for 
international energy export.
    Plentiful domestic natural gas supply and comparatively low natural 
gas prices have changed the economics of electric power markets.\17\ 
Further, new environmental standards at the local, state, regional, and 
Federal levels have encouraged switching to fuels with lower emissions 
profiles, including natural gas and renewables. U.S. natural gas 
consumption for power generation grew from 15.8 billion cubic feet per 
day (Bcf/d) in 2005 to 22.2 Bcf/d in 2013, and demand is projected to 
increase by another 8.9 Bcf/d by 2030.\18\ Net gas-fired electricity 
generation increased 73 percent nationally from 2003 to 2013, and 
natural gas-fired power plants accounted for more than 50 percent of 
new utility-scale generating capacity added in 2013. To accommodate 
continued future growth in natural gas-fueled power, changes in 
pipeline infrastructure will be needed, including reversals of existing 
pipelines; additional lines to gas-fired generators; looping of the 
existing network, where pipelines are laid parallel to one another 
along a single right-of-way to increase capacity; and potentially new 
pipelines as well.
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    \17\ Id., at NG-9.
    \18\ Id.
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    Further, the increased availability of low-cost natural gas has 
brought jobs back to American soil, and increasing investment in 
projects designed to take advantage of the significant increase in 
supplies of low-cost gas available in the U.S. suggests this trend will 
continue.\19\ Moreover, low domestic prices and high international 
prices have made natural gas export increasingly attractive to American 
businesses. The Federal Energy Regulatory Commission, as of September 
2015, estimated U.S. LNG prices at $2.25-$2.41 per million Btu, while 
prices in areas of Asia, Europe, and South America ranged from $6.30 to 
$7.62 per million Btu.\20\ Due to high capital investment barriers and 
coordination difficulties between pipeline shippers, the maritime 
shipping industry, and pipeline operators, there are not enough ships 
and processing facilities to transport enough LNG to equalize prices. 
Taking advantage of these price differentials, liquefied natural gas 
exporting terminals in the U.S. and British Columbia, Canada, are 
projected to demand between 5.1 Bcf/d and 8.3 Bcf/d of gas by 2030.\21\
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    \19\ Id., at NG-10.
    \20\ https://www.ferc.gov/market-oversight/mkt-gas/overview/ngas-ovr-lng-wld-pr-est.pdf.
    \21\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' 
Quadrennial Energy Review Report: Energy Transmission, Storage, and 
Distribution Infrastructure, p. NG-11, April 2015.
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Increasing Pressures on the Existing Pipeline System Due to Supply and 
Demand Changes
    Despite the significant increase in domestic gas production, the 
widespread distribution of domestic gas demand, combined with 
significant flexibility and capacity in the existing transmission 
system, mitigates the level of pipeline expansion and investment 
required to accommodate growing and shifting demand. Some of the new 
gas production is located near existing or emerging sources of demand, 
which reduces the need for additional natural gas pipeline 
infrastructure. In many instances where new natural gas pipelines are 
needed, the network is being expanded by participants pursuing lowest-
cost options to move product to market--often making investments to 
enhance network capacity on existing lines rather than increasing 
coverage through new infrastructure. Where this capacity is not 
increasing via additional mileage, it is increasing through larger 
pipeline diameters or higher operating pressures. In short, the 
nation's existing, and in many cases, aging, pipeline system is facing 
the full brunt of this dramatic increase in natural gas supply and the 
shifting energy needs of the country.
    The U.S. Energy Information Administration estimates that between 
2004 and 2013, the natural gas industry spent about $56 billion 
expanding the natural gas pipeline network. Between 2008 and 2013, 
pipeline capacity additions totaled more than 110 Bcf/d.\22\ Despite 
this increase in capacity, gas transmission mileage decreased from 
299,358 miles in 2010 to 298,287 miles in 2013.
---------------------------------------------------------------------------

    \22\ Id., at NG-31.
---------------------------------------------------------------------------

    Building new infrastructure, or replacing and modernizing old 
infrastructure, is expensive and requires a long lead-time for 
planning. Frequently, the most inexpensive way to move new production 
to demand centers is by using available existing infrastructure. For 
several reasons, the U.S.'s extensive pre-existing gas network is 
currently underutilized: (1) Pipelines are long-lived assets that 
reflect historic supply and demand trends; (2) pipelines often are 
sized to meet high initial production levels and

[[Page 20727]]

have excess long-term capacity due to changing economics; and (3) 
pipelines that were built specifically to provide gas to residential 
and commercial consumers in cold-weather regions but not for power 
generation are often under-utilized during off-peak seasons.
    In cases where utilization of the existing pipeline network is 
high, the next most cost-effective solution is to add capacity to 
existing lines via compression. While this is technically a form of 
infrastructure investment, it is less costly, faster, and simpler for 
market participants in comparison to building a new pipeline. Adding 
compression, however, may raise average pipeline operating pressures, 
exposing previously hidden defects.
    Developers also recognize that building new pipelines is 
challenging due to societal fears and cost, so new pipelines are 
typically designed in such a way that they can handle additional 
capacity if needed. In New England, new pipeline projects have been 
proposed to address pending supply constraints and higher prices. 
However, public acceptance presents a substantial challenge to natural 
gas pipeline development. Investments and proposals to pay for new 
natural gas transmission pipeline capacity and services often face 
significant challenges in determining feasible rights of way and 
developing community support for the projects.
Data Challenges
    Because there is so much emphasis on using the existing pipeline 
system to meet the country's energy needs, it is increasingly important 
for that system to be safe and efficient. In order to keep the public 
safe and to assure the nation's energy security, operators and 
regulators must have an intimate understanding of the threats to and 
operations of the entire pipeline system.
    Data gathering and integration are important elements of good IM 
practices, and while many strides have been made over the years to 
collect more and better data, several data gaps still exist. 
Ironically, the comparatively positive safety record of the nation's 
pipeline system to date makes it harder to quantify some of these gaps. 
Over the 20-year period of 1995-2014, transmission facilities accounted 
for 42 fatalities and 174 injuries, or about one-seventh of the total 
fatalities and injuries on the nation's natural gas pipeline 
system.\23\ Over the 4-year period of 2011-2014, there was only 1 
transmission-related fatality. Fortunately, there have been only 
limited ``worst-case scenarios'' to evaluate for cost/benefit analysis 
of measures to improve safety, so there are limited bases for 
projecting the possible impacts of low-probability, high-consequence 
events.
---------------------------------------------------------------------------

    \23\ PHMSA, Pipeline Incident 20-Year Trends, http://www.phmsa.dot.gov/pipeline/library/data-stats/pipelineincidenttrends.
---------------------------------------------------------------------------

    On September 9, 2010, a 30-inch-diameter segment of an intrastate 
natural gas transmission pipeline owned and operated by the Pacific Gas 
and Electric Company ruptured in a residential area of San Bruno, 
California. The rupture produced a crater about 72 feet long by 26 feet 
wide. The section of pipe that ruptured, which was about 28 feet long 
and weighed about 3,000 pounds, was found 100 feet south of the crater. 
The natural gas that was released subsequently ignited, resulting in a 
fire that destroyed 38 homes and damaged 70. Eight people were killed, 
many were injured, and many more were evacuated from the area.
    The San Bruno incident exposed several problems in the way data on 
pipeline conditions is collected and managed, showing that many 
operators have inadequate records regarding the physical and 
operational characteristics of their pipelines. Many of these records 
are necessary for the correct setting and validation of MAOP, which is 
critically important for providing an appropriate margin of safety to 
the public.
    Much of operator and PHMSA's data is obtained through testing and 
inspection under IM requirements. However, this testing can be 
expensive, and the approaches to obtaining data that are most efficient 
over the long term may require significant upfront costs to modernize 
pipes and make them suitable for automated inspection. As a result, 
there continue to be data gaps that make it hard to fully understand 
the risks to and the integrity of the nation's pipeline system.
    To assess a pipeline's integrity, operators generally choose 
between three methods of testing a pipeline: Inline inspection (ILI), 
pressure testing, and direct assessment (DA). There is a marked 
difference in the distribution of assessment methods between interstate 
and intrastate pipelines. In 2013, we estimate that about two-thirds of 
interstate pipeline mileage was suitable for in-line inspection, 
compared to only about half of intrastate pipeline mileage. Because a 
larger percentage of intrastate pipelines are unable to accommodate ILI 
tools, intrastate operators use more pressure testing and DA than 
interstate operators.
    ILIs are performed by using special tools, sometimes referred to as 
``smart pigs,'' which are usually pushed through a pipeline by the 
pressure 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 prevent excessive 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.
    Pressure tests are typically used by pipeline operators as a means 
to determine the integrity (or strength) of the pipeline immediately 
after construction and before placing the pipeline in service, as well 
as periodically during a pipeline's operating life. In a pressure test, 
a test medium 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 (DA) is the evaluation of various locations on a 
pipeline for corrosion threats. Operators will review records, 
indirectly inspect the pipeline, or use mathematical models and 
environmental surveys to find likely locations on a pipeline where 
corrosion might be occurring. Areas that are likely to have suffered 
from corrosion are subsequently excavated and examined. DA can be 
prohibitively expensive to use unless targeting specific locations, 
which may not give an accurate representation of the condition of 
lengths of entire pipeline segments.
    Ongoing research and industry response to the ANPRM \24\ appear to 
indicate that ILI and spike hydrostatic pressure testing is more 
effective than DA for identifying pipe conditions that are related to 
stress corrosion cracking defects. 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, occasional disruptions in service, and substantial methane 
emissions due to the routine evacuation of natural gas from pipelines 
prior to tests. Further, many operators prefer not to use hydrostatic 
pressure tests because it can potentially be a

[[Page 20728]]

destructive method of testing.\25\ ILI testing can obtain data along a 
pipeline not otherwise obtainable via other assessment methods, 
although this method also has certain limitations.
---------------------------------------------------------------------------

    \24\ ``Pipeline Safety: Safety of Gas Transmission Pipelines--
Advanced Notice of Proposed Rulemaking,'' 76 FR 5308; August 25, 
2011.
    \25\ National Transportation Safety Board, ``Pacific Gas and 
Electric Company; Natural Gas Transmission Pipeline Rupture and 
Fire; San Bruno, California; September 9, 2010,'' Pipeline Accident 
Report NTSB/PAR-11-01, Page 96, 2011.
---------------------------------------------------------------------------

    In this proposed rulemaking, PHMSA would expand the range of 
permissible assessment methods while imposing new requirements to guide 
operators' selection of appropriate methods. Allowing alternatives to 
hydrostatic testing (including ILI technologies), combined with further 
research and development to make ILI testing more accurate, could help 
to drive innovation in pipeline integrity testing technologies. This 
could eventually lead to improved safety and system reliability through 
better data collection and assessment.
Increased and Changing Use, Coupled With Age, Exposure to Weather, and 
Other Factors Can Increase the Risk of Pipeline Incidents
    While the existing pipeline network's capacity is expected to bear 
the brunt of the increasing demand for natural gas in this country, due 
in part due to the location of new gas resources, new production 
patterns are causing unique concerns for some pipeline operators. The 
significant growth of production outside the Gulf Coast region--
especially in Pennsylvania and Ohio--is causing a reorientation of the 
nation's transmission pipeline network. The most significant of these 
changes will require reversing flows on pipelines to move Marcellus and 
Utica gas to the southeastern Atlantic region and the Midwest.
    Reversing a pipeline's flow can cause added stresses on the system 
due to changes in pressure gradients, flow rates, and product velocity, 
which can create new risks of internal corrosion. Occasional failures 
on natural gas transmission pipelines have occurred after operational 
changes that include flow reversals and product changes. PHMSA has 
noticed a large number of recent or proposed flow reversals and product 
changes on a number of gas transmission lines. In response to this 
phenomenon, PHMSA issued an Advisory Bulletin notifying operators of 
the potentially significant impacts such changes may have on the 
integrity of a pipeline.\26\
---------------------------------------------------------------------------

    \26\ ``Pipeline Safety: Guidance for Pipeline Flow Reversals, 
Product Changes, and Conversion to Service,'' ADB PHMSA-2014-0040, 
79 FR 56121; September 18, 2014.
---------------------------------------------------------------------------

    Further, the rise of shale gas production is altering not just the 
extent, but also the characteristics of the nation's gas gathering 
systems. Gas fields are being developed in new geographic areas, thus 
requiring entirely new gathering systems and expanded networks of 
gathering lines. Producers are employing gathering lines with diameters 
as large as 36 inches and maximum operating pressures up to 1480 psig, 
far exceeding historical design and operating pressure of typical 
gathering lines and making them similar to large transmission lines. 
Most of these new gas gathering lines are unregulated, and PHMSA does 
not collect incident data or report annual data on these unregulated 
lines.
    However, PHMSA is aware of incidents that show gathering lines are 
subject to the same sorts of failures common to other pipelines that 
the agency does regulate. For example, on November 14, 2008, three 
homes were destroyed and one person was injured when a gas gathering 
line ruptured in Grady County, OK. On June 8, 2010, two workers died 
when a bulldozer struck a gas gathering line in Darrouzett, TX, and on 
June 29, 2010, three men working on a gas gathering line in Grady 
County, OK, were injured when it ruptured. The dramatic expansion in 
natural gas production and changes in typical gathering line 
characteristics require PHMSA to review its regulatory approach to gas 
gathering pipelines to address new safety and environmental risks.
    In addition to demands placed on the nation's pipeline system due 
to increased and changing use, there are many other factors--including 
recurring issues that IM was initially developed to address--that 
affect the integrity of the nation's pipelines.
    Data indicate that some pipelines continue to be vulnerable to 
issues stemming from outdated construction methods or materials. Much 
of the older line pipe in the nation's gas transmission infrastructure 
was made before the 1970s using techniques that have proven to contain 
latent defects due to the manufacturing process. For example, line pipe 
manufactured using low frequency electric resistance welding is 
susceptible to seam failure. Because these manufacturing techniques 
were used during the time before the Federal gas regulations were 
issued, many of those pipes are subsequently exempt from certain 
regulations, most notably the requirement to pressure test the pipeline 
or otherwise verify its integrity to establish MAOP. A substantial 
amount of this type of pipe is still in service. 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. The NTSB's investigation 
of the San Bruno incident determined that the pipe failed due to a 
similar defect. Additionally, between 2010 and 2014, fifteen other 
reportable incidents were attributed to seam failures, resulting in 
over $8 million of property damage.
    The nation's pipeline system also faces a greater risk from failure 
due to extreme weather events such as hurricanes, floods, mudslides, 
tornadoes, and earthquakes. A 2011 crude oil spill into the Yellowstone 
River 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. In October 1994, flooding 
along the San Jacinto River led to the failure of eight hazardous 
liquid pipelines and also undermined a number of other pipelines. The 
escaping products were ignited, leading to smoke inhalation and burn 
injuries of 547 people. From 2003 to 2013, there were 85 reportable 
incidents in which storms or other severe natural force conditions 
damaged pipelines and resulted in their failure. Operators reported 
total damages of over $104M from these incidents. 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.
    Considering recent incidents and many of the factors outlined 
above, PHMSA believes IM has led to several improvements in managing 
pipeline safety, yet the agency believes there is still more to do to 
improve the safety of natural gas transmission pipelines and ensure 
public confidence.
Challenges to Modernization and Historical Problems Underscore the Need 
for a Clear Strategy To Protect the Safety and Integrity of the 
Nation's Pipeline System
    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. The objectives of IM 
are to accelerate and improve the quality of integrity assessments, 
promote more rigorous and systematic management of integrity, 
strengthen oversight, and increase public confidence. On the operator 
level, an IM program consists of multiple

[[Page 20729]]

components, including adopting procedures and processes to identify 
HCAs, 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.
    The initial definition for HCAs was finalized on August 6, 
2002,\27\ providing concentrations of populations with corridors of 
protection spanning 300, 660, or 1,000 feet, depending on the diameter 
and MAOP of the particular pipeline.\28\ In a later NPRM,\29\ PHMSA 
proposed changes to the definition of a HCA by introducing the concept 
of a covered segment, which PHMSA defined as the length of gas 
transmission pipeline that could potentially impact an HCA.\30\ 
Previously, only distances from the pipeline centerline related to HCA 
definitions. PHMSA also proposed using Potential Impact Circles, 
Potential Impact Zones, and Potential Impact Radii (PIR) to identify 
covered segments instead of a fixed corridor width. The final Gas 
Transmission Pipeline Integrity Management Rule, incorporating the new 
HCA definition, was issued on December 15, 2003.\31\
---------------------------------------------------------------------------

    \27\ ``Pipeline Safety: High Consequence Areas for Gas 
Transmission Pipelines,'' Final rule, 67 FR 50824; August 6, 2002.
    \28\ The influence of the existing class location concept on the 
early definition of HCAs is evident from the use of class locations 
themselves in the definition, and the use of fixed 660 ft. 
distances, which corresponds to the corridor width used in the class 
location definition. This concept was later significantly revised, 
as discussed later, in favor of a variable corridor width (referred 
to as the Potential Impact Radius) based on case-specific pipe size 
and operating pressure.
    \29\ ``Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Gas Transmission Pipelines),'' Notice of Proposed 
Rulemaking, 68 FR 4278; January 28, 2003.
    \30\ HCA and PIR definitions are in 49 CFR 192.903.
    \31\ ``Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Gas Transmission Pipelines),'' Final rule, 68 FR 
69778; December 15, 2003.
---------------------------------------------------------------------------

    The incident at San Bruno in 2010 motivated a comprehensive 
reexamination of gas transmission pipeline safety. Congress responded 
to concerns in light of the San Bruno incident by passing the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011, which 
directed the DOT to reexamine many of its safety requirements, 
including the expansion of IM regulations for transmission pipelines.
    Further, both the NTSB and the GAO issued several recommendations 
to PHMSA to improve its IM program and pipeline safety. The NTSB noted, 
in a 2015 study,\32\ that IM requirements have reduced the rate of 
failures due to deterioration of pipe welds, corrosion, and material 
failures. However, pipeline incidents in high-consequence areas due to 
other factors increased between 2010 and 2013, and the overall 
occurrence of gas transmission pipeline incidents in high-consequence 
areas has remained stable. The NTSB also found many types of basic data 
necessary to support comprehensive probabilistic modeling of pipeline 
risks are not currently available.
---------------------------------------------------------------------------

    \32\ National Transportation Safety Board, ``Safety Study: 
Integrity Management of Gas Transmission Pipelines in High 
Consequence Areas,'' NTSB SS-15/01, January 27, 2015.
---------------------------------------------------------------------------

    Many of these mandates and recommendations caused PHMSA to evaluate 
whether IM system requirements, or elements thereof, should be expanded 
beyond HCAs to afford protection to a larger percentage of the nation's 
population. Additionally, several of these mandates and recommendations 
asked PHMSA to enhance the existing IM regulations by addressing MAOP 
verification, inadequate operator records, legacy pipe issues, and 
inadequate integrity assessments. Further, PHMSA was charged with 
reducing data gaps and improving data integration, considering the 
regulatory framework for gas gathering systems, and deleting the 
``grandfather clause'' to require all gas transmission pipelines 
constructed before 1970 be subjected to a hydrostatic spike pressure 
test. This proposed rule addresses several of the recommendations from 
the 2015 study including P-15-18 (IM-ILI capability), P-15-20 (IM-ILI 
tools), P-15-21 (IM-Direct Assessments), and P-21 (IM-Data 
Integration).
PHMSA Is Delivering a Comprehensive Strategy To Protect the Nation's 
Pipeline System While Accounting for a Changing Landscape and a 
Changing Population
    To address these statutory mandates, the post-San Bruno NTSB and 
GAO recommendations, and other pipeline safety mandates, PHMSA posed a 
series of questions to the public in the context of an August 2011 
ANPRM titled ``Pipeline Safety: Safety of Gas Transmission Pipelines'' 
(PHMSA-2011-0023). In that document, PHMSA asked whether the 
regulations governing the safety of gas transmission pipelines needed 
changing. In particular, PHMSA asked whether IM requirements should be 
changed, including through adding more prescriptive language in some 
areas, and whether other issues related to system integrity should be 
addressed by strengthening or expanding non-IM requirements. Among the 
specific issues PHMSA considered concerning IM requirements were 
whether the definition of an HCA should be revised, and whether 
additional restrictions should be placed on the use of specific 
pipeline assessment methods. In the ANPRM, PHMSA also considered 
changes to non-IM requirements, including valve spacing and 
installation, corrosion control, and whether regulations for gathering 
lines needed to be modified.
    PHMSA received 103 comments in response to the ANPRM, which are 
summarized in more detail later in this document. Feedback from the 
ANPRM helped to identify a series of common-sense improvements to IM, 
including improvements to assessment goals such as integrity 
verification, MAOP verification, and material documentation; clarified 
repair criteria; clarified protocol for identifying threats, risk 
assessments and management, and prevention and mitigation measures; 
expanded and enhanced corrosion control; requirements for inspecting 
pipelines after incidents of extreme weather; and new guidance on how 
to calculate MAOP in order to set operating parameters more accurately 
and predict the risks of an incident.
    Many of these aspects of IM have been an integral part of PHMSA's 
expectations since the inception of the IM program. As specified in the 
first IM rule, PHMSA expects operators to start with an IM framework, 
evolve a more detailed and comprehensive IM program, and continually 
improve their IM programs as they learn more about the IM process and 
the material condition of their pipelines through integrity 
assessments. This NPRM's proposals regarding operators' processes for 
implementing IM reflect PHMSA's expectations regarding the degree of 
progress operators should be making, or should have made, during the 
first 10 years of IM program implementation.
    To address issues involving the increased risk posed by larger-
diameter, higher-pressure gathering lines, PHMSA is proposing to issue 
requirements for certain currently unregulated gas gathering pipelines 
that are intended to prevent the most frequent causes of failure--
corrosion and excavation damage--and to improve emergency response 
preparedness. Minimum Federal safety standards would also bring an 
appropriate level of consistency to the current mix of regulations that 
differ from state to state.

[[Page 20730]]

    PHMSA believes these proposed changes will improve the safety and 
protection of pipeline workers, the public, property, and the 
environment by improving the detection and remediation of unsafe 
conditions, ensuring that certain currently unregulated pipelines are 
subject to appropriate regulatory oversight, and speeding mitigation of 
adverse effects of pipeline failures. In addition to safety benefits, 
the rule is expected to improve the performance and extend the economic 
life of critical pipeline infrastructure that transports domestically 
produced natural gas energy, thus supporting national economic and 
security energy objectives.
Looking at Risk Beyond HCAs
    In addition to the common sense improvements to IM, responses to 
the ANPRM reinforced the importance of carefully reconsidering the 
scope of areas covered by IM. While PHMSA's IM program manages risks 
primarily by focusing oversight on areas with the greatest population 
density, responses to the ANPRM highlight the imperative of protecting 
the safety of communities throughout the country in light of a changing 
landscape of production, consumption, and product movement that merits 
a refreshed look at the current scope of IM coverage.
    In the 2011 Act, Congress required PHMSA to have pipeline operators 
conduct a records verification to ensure that their records accurately 
reflect the physical and operational characteristics of pipelines in 
certain HCAs and class locations, and to confirm the established MAOP 
of the pipelines. The results of that action indicate that problems 
similar to the contributing factors of the San Bruno incident are more 
widespread than previously believed, affecting both HCA and non-HCA 
segments. This indicates that a rupture on the scale of San Bruno, with 
the potential to affect populations, the environment, or commerce, 
could occur elsewhere on the nation's pipeline system.
    In fact, devastating incidents have occurred outside of HCAs in 
rural areas where populations are sparse but present. On August 19, 
2000, a 30-inch-diameter gas transmission pipeline ruptured adjacent to 
the Pecos River near Carlsbad, NM. The released gas ignited and burned 
for 55 minutes. Twelve persons who were camping under a concrete-decked 
steel bridge that supported the pipeline across the river were killed, 
and their vehicles were destroyed. Two nearby steel suspension bridges 
for gas pipelines crossing the river were damaged extensively.
    On December 14, 2007, two men were driving in a pickup truck on 
Interstate 20 near Delhi, LA, when a 30-inch gas transmission pipeline 
ruptured. One of the men was killed, and the other was injured.
    On December 11, 2012, a 20-inch-diameter gas transmission line 
ruptured in a sparsely populated area about 106 feet west of Interstate 
77 (I-77) in Sissonville, WV. An area of fire damage about 820 feet 
wide extended nearly 1,100 feet along the pipeline right-of-way. Three 
houses were destroyed by the fire, and several other houses were 
damaged. Reported losses, repairs, and upgrades from this incident 
totaled over $8.5 million, and major transportation delays occurred. I-
77 was closed in both directions because of the fire and resulting 
damage to the road surface. The northbound lanes were closed for about 
14 hours, and the southbound lanes were closed for about 19 hours while 
the road was resurfaced, causing delays to both travelers and 
commercial shipping.
    Because the nation's population is growing, moving, and dispersing, 
population density is a changing measure, and we need to be prepared 
for further shifts in the coming decades. The current definition of an 
HCA uses building density as a proxy for approximating the presence of 
communities and surrounding infrastructure. This can be a meaningful 
metric for prioritizing implementation of safety and risk management 
protocols for areas where an accident would have the greatest 
likelihood of putting human life in danger, but it is not necessarily 
an accurate reflection of whether an incident will have a significant 
impact on people. Requiring assessment and repair criteria for 
pipelines that, if ruptured, could pose a threat to areas where any 
people live, work, or congregate would improve public safety and would 
improve public confidence in the nation's natural gas pipeline system.
    Feedback from industry indicated that some pipeline operators are 
already moving towards expanding the protections of IM beyond HCAs. In 
2012, the Interstate Natural Gas Association of America (INGAA) issued 
a ``Commitment to Pipeline Safety,'' \33\ underscoring its efforts 
towards a goal of zero incidents, a committed safety culture, a pursuit 
of constant improvement, and applying IM principles on a system-wide 
basis. INGAA divides the commitment into four stages:
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    \33\ Letter from Terry D. Boss, Senior Vice President of 
Environment, Safety and Operations to Mike Israni, Pipeline and 
Hazardous Materials Safety Administration, U.S. Department of 
Transportation, dated January 20, 2012, ``Safety of Gas Transmission 
Pipelines, Docket No. PHMSA-2011-0023.'' INGAA represents companies 
that operate approximately 65 percent of the gas transmission 
pipelines, but INGAA does not represent all pipeline operators 
subject to 49 CFR part 192.
---------------------------------------------------------------------------

     Stage 1--INGAA members will complete an initial assessment 
using some degree of IM on their pipelines, covering 90% of the 
population living, working, or congregating along INGAA member 
pipelines, by the end of 2012. This represents roughly 64% of INGAA 
member pipeline mileage, including the 4% of pipelines that are in 
HCAs.
     Stage 2--By 2020, INGAA members will consistently and 
comprehensively apply IM principles to those pipelines.
     Stage 3--By 2030, INGAA members will apply IM principles 
to pipelines, extending IM protection to 100% of the population living 
along INGAA member pipelines. This stage would cover roughly 16% of 
pipeline mileage, bringing the total coverage by 2030 to approximately 
80% of INGAA's pipeline mileage.
     Stage 4--Beyond 2030, INGAA members will apply IM 
principles to the remaining 20% of pipeline mileage where no population 
resides.
    To accomplish this commitment, INGAA's members are performing 
actions that include applying risk management beyond HCAs; raising the 
standards for corrosion management; demonstrating ``fitness for 
service'' on pre-regulation pipelines; and evaluating, refining, and 
improving operators' ability to assess and mitigate safety threats. 
Ultimately, these actions aim to extend protection to people who live 
near pipelines but not within defined HCAs.
    INGAA's commitment and other stakeholder feedback on this issue 
have triggered an important exchange about measuring the risks that 
exist in less-densely populated areas and the impacts of expanding 
greater protections to those areas. If constant improvement and zero 
incidents are goals for pipeline operators, INGAA's plan to extend and 
prioritize IM assessments and principles to all parts of their pipeline 
networks that are located near any concentrations of population is an 
effective way to achieve those goals. Such an approach is needed to 
help clarify vulnerabilities and prioritize improvements, and this 
proposed rulemaking takes important steps forward towards developing 
such an approach.

[[Page 20731]]

    The question then, is how to implement risk management standards 
that most accurately target the safety of communities, while also 
providing sufficient ability to prioritize areas of greatest possible 
risk and/or impact. Addressing that question has been, and remains, an 
important part of this proposed rule, recognizing that the answer will 
remain fluid based on factors that continue to change.
    Given INGAA's commitment, feedback from the ANPRM, the results of 
incident investigations, and IM considerations, PHMSA has determined it 
is appropriate to improve aspects of the current IM program and codify 
requirements for additional gas transmission pipelines to receive 
integrity assessments on a periodic basis to monitor for, detect, and 
remediate pipeline defects and anomalies. In addition, in order to 
achieve the desired outcome of performing assessments in areas where 
people live, work, or congregate, while minimizing the cost of 
identifying such locations, PHMSA proposes to base the requirements for 
identifying those locations on processes already being implemented by 
pipeline operators and that protect people on a risk-prioritized basis.
    Establishing integrity assessment requirements and associated 
repair conditions for non-HCA pipe segments is important for providing 
safety to the public. Although those segments are not within defined 
HCAs, they will usually be located in populated areas, and pipeline 
accidents in these areas may cause fatalities, significant property 
damage, or disrupt livelihoods. This rulemaking proposes a newly 
defined moderate consequence area (MCA) to identify additional non-HCA 
pipeline segments that would require integrity assessments, thus 
assuring timely discovery and repair of pipeline defects in MCA 
segments. These changes would ensure prompt remediation of anomalous 
conditions that could potentially impact people, property, or the 
environment, and commensurate with the severity of the defects, while 
at the same time allowing operators to allocate their resources to HCAs 
on a higher-priority basis. INGAA's commitment and PHMSA's MCA 
definition are comparable, which shows a common understanding of the 
importance of this issue and a path towards a solution.

B. Advance Notice of Proposed Rulemaking

    On August 25, 2011, PHMSA published an Advance Notice of Proposed 
Rulemaking (ANPRM) to seek public comments regarding the revision of 
the Pipeline Safety Regulations applicable to the safety of gas 
transmission pipelines. In particular, PHMSA requested comments 
regarding whether integrity management (IM) requirements should be 
changed and whether other issues related to system integrity should be 
addressed by strengthening or expanding non-IM requirements. The ANPRM 
may be viewed at http://www.regulations.gov by searching for Docket ID 
PHMSA-2011-0023. As mentioned above, pursuant to the related issues 
raised by the NTSB recommendations and statutory requirements of the 
Act, PHMSA is issuing separate rulemaking for several of the topics in 
the ANPRM. These topics are so designated in the following list. 
Specifically, the ANPRM sought comments on the following topics:
    A. Modifying the Definition of HCA (to be addressed in separate 
rulemaking),
    B. Strengthening Requirements to Implement Preventive and 
Mitigative Measures for Pipeline Segments in HCAs (partially addressed 
in separate rulemaking--aspects related to Remote Control Valves and 
Leak Detection will be addressed in separate rulemaking, other aspects 
are being addressed in this NPRM),
    C. Modifying Repair Criteria,
    D. Improving Requirements for Collecting, Validating, and 
Integrating Pipeline Data,
    E. Making Requirements Related to the Nature and Application of 
Risk Models More Prescriptive,
    F. Strengthening Requirements for Applying Knowledge Gained Through 
the IM Program,
    G. Strengthening Requirements on the Selection and Use of 
Assessment Methods,
    H. Valve Spacing and the Need for Remotely or Automatically 
Controlled Valves (to be addressed in separate rulemaking),
    I. Corrosion Control,
    J. Pipe Manufactured Using Longitudinal Weld Seams,
    K. Establishing Requirements Applicable to Underground Gas Storage 
(to be considered for separate rulemaking),
    L. Management of Change,
    M. Quality Management Systems (QMS) (to be considered for separate 
rulemaking),
    N. Exemption of Facilities Installed Prior to the Regulations,
    O. Modifying the Regulation of Gas Gathering Lines.
    A summary of comments and responses to those comments are provided 
later in the document.

C. National Transportation Safety Board Recommendations

    On August 30, 2011, following the issuance of the ANPRM, the NTSB 
adopted its report on the gas pipeline accident that occurred on 
September 9, 2010, in San Bruno, California. On September 26, 2011, the 
NTSB issued safety recommendations P-11-8 through -20 to PHMSA, and 
issued safety recommendations P-10-2 through -4 to Pacific Gas & 
Electric (PG&E), among others. The NTSB made these recommendations 
following its investigation of the tragic September 9, 2010 natural gas 
pipeline rupture in the city of San Bruno, California. Several of the 
NTSB recommendations related directly to the topics addressed in the 
August 25, 2011 ANPRM and impacted the proposed approach to rulemaking. 
The potentially impacted topics and the related NTSB recommendations 
include, but are not limited to:
     Topic B--Strengthening Requirements to Implement 
Preventive and Mitigative Measures for Pipeline Segments in HCAs. NTSB 
Recommendation P-11-10: ``Require that all operators of natural gas 
transmission and distribution pipelines equip their supervisory control 
and data acquisition systems with tools to assist in recognizing and 
pinpointing the location of leaks, including line breaks; such tools 
could include a real-time leak detection system and appropriately 
spaced flow and pressure transmitters along covered transmission 
lines.''
     Topic D--Improving Requirements for Collecting, 
Validating, and Integrating Pipeline Data. NTSB Recommendation P-11-19: 
``(1) Develop and implement standards for integrity management and 
other performance-based safety programs that require operators of all 
types of pipeline systems to regularly assess the effectiveness of 
their programs using clear and meaningful metrics, and to identify and 
then correct deficiencies; and (2) make those metrics available in a 
centralized database.''
     Topic G--Strengthening Requirements on the Selection and 
Use of Assessment Methods. NTSB Recommendation P-11-17: ``Require that 
all natural gas transmission pipelines be configured so as to 
accommodate in-line inspection tools, with priority given to older 
pipelines.''
     Topic H--Valve Spacing and the Need for Remotely or 
Automatically Controlled Valves. NTSB Recommendation P-11-11: ``Amend 
Title 49 Code of Federal Regulations Section 192.935(c) to directly 
require that automatic shutoff valves or remote

[[Page 20732]]

control valves in high consequence areas and in class 3 and 4 locations 
be installed and spaced at intervals that consider the population 
factors listed in the regulations.''
     Topic J--Pipe Manufactured Using Longitudinal Weld Seams. 
NTSB Recommendation P-11-15: ``Amend Title 49 Code of Federal 
Regulations Part 192 of the Federal pipeline safety regulations so that 
manufacturing- and construction-related defects can only be considered 
stable if a gas pipeline has been subjected to a post-construction 
hydrostatic pressure test of at least 1.25 times the maximum allowable 
operating pressure.''
     Topic N--Exemption of Facilities Installed Prior to the 
Regulations. NTSB Recommendation P-11-14: Amend title 49 Code of 
Federal Regulations 192.619 to repeal exemptions from pressure test 
requirements and require that all gas transmission pipelines 
constructed before 1970 be subjected to a hydrostatic pressure test 
that incorporates a spike test.''

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

    Also subsequent to issuance of the ANPRM, the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011 (the Act) was 
enacted on January 3, 2012. Several of the Act's statutory requirements 
relate directly to the topics addressed in the August 25, 2011 ANPRM. 
The related topics and statutory citations include, but are not limited 
to:
    [cir] Section 5(e)--Allow periodic reassessments to be extended for 
an additional 6 months if the operator submits sufficient 
justification.
    [cir] Section 5(f)--Requires regulations issued by the Secretary, 
if any, to expand integrity management system requirements, or elements 
thereof, beyond high-consequence areas.
    [cir] Section 21--Regulation of Gas (and Hazardous Liquid) 
Gathering Lines
    [cir] Section 23--Testing regulations to confirm the material 
strength of previously untested natural gas transmission pipelines.
    [cir] Section 29--Consider seismicity when evaluating pipeline 
threats.

E. Summary of Each Topic Under Consideration

    This NPRM proposes new requirements and revisions to existing 
requirements to address topics discussed in the ANPRM, including some 
topics from the Act and the NTSB recommendations. Each topic area 
discussed in the ANPRM, as well as additional topics that have arisen 
since issuance of the ANPRM, is summarized below. Details of the 
changes proposed in this rule are discussed below in section V. 
Section-by-Section Analysis.
     Topic A--Modifying the Definition of HCA. The ANPRM 
requested comments regarding expanding the definition of an HCA so that 
more miles of pipe would be subject to IM requirements and so that all 
Class 3 and 4 locations would be subject to the IM requirements. The 
Act, Section 5, requires that the Secretary of Transportation complete 
an evaluation and issue a report on whether integrity management 
requirements should be expanded beyond HCAs and whether such expansion 
would mitigate the need for class location requirements. PHMSA has 
prepared the class location report and a copy is available in the 
docket (www.regulations.gov) for this proposed rulemaking. PHMSA 
invites commenters to review the class location report when formulating 
their comments.
    Although PHMSA is not proposing to expand the definition of an HCA, 
PHMSA is proposing to expand certain IM requirements beyond HCAs by 
creating a new ``moderate consequence areas (MCA).'' MCAs would be used 
to define the subset of non-HCA pipeline locations where periodic 
integrity assessments are required (Sec.  192.710), where material 
documentation verification is required (Sec.  192.607), and where MAOP 
verification is required (Sec. Sec.  192.619(e) and 192.624). The 
proposed criteria for determining MCA locations would use the same 
process and the same definitions as currently used to identify HCAs, 
except that the threshold for buildings intended for human occupancy 
and the threshold for persons that occupy other defined sites, that are 
located within the potential impact radius, would both be lowered from 
20 to 5. The intention is that any pipeline location at which persons 
are normally expected to be located would be afforded extra safety 
protections described above. In addition, as a result of the 
Sissonville, West Virginia incident, NTSB issued recommendation P-14-
01, to revise the gas regulations to add principal arterial roadways 
including interstates, other freeways and expressways, and other 
principal arterial roadways as defined in the Federal Highway 
Administration's Highway Functional Classification Concepts, Criteria 
and Procedures to the list of ``identified sites'' that establish a 
high consequence area. PHMSA proposes to meet the intent of NTSB's 
recommendation by incorporating designated interstates, freeways, 
expressways, and other principal 4-lane arterial roadways (as opposed 
to NTSB's all ``other principal arterial roadways'') within the new 
definition of MCAs. PHMSA believes this approach would be cost-
beneficial. The Sissonville, WV, incident location would not meet the 
current definition of an HCA, but would, however, meet the proposed 
definition of an MCA. PHMSA considered expanding the scope of HCAs 
instead of creating Moderate Consequence Areas. Such an approach was 
contemplated in the 2011 ANPRM and PHMSA received a number of comments 
on this approach. PHMSA concluded that this approach would be counter 
to a graded approach based on risk (i.e., risk based gradation of 
requirements to apply progressively more protection for progressively 
greater consequence locations). By simply expanding HCAs, PHMSA would 
be simply lowering the threshold for what is considered ``high 
consequence.'' Expanding HCAs would require that all integrity 
management program elements (specified in subpart O) be applied to pipe 
located in a newly designated HCA. The proposed rule would only apply 
three IM program elements (assessment, periodic reassessment, and 
remediation of discovered defects) to the category of pipe that has 
lesser consequences than HCAs (i.e., MCAs), but not to segments without 
any structure or site within the PIR (arguably ``low consequence 
areas''). There would be additional significant costs to apply all 
other integrity management program elements (most notably the risk 
analysis and preventive/mitigative measures program elements) to 
additional segments currently not designated as HCA. Also, if HCAs were 
expanded, long term reassessment costs would approximately triple 
(compared to the proposed MCA requirements) based on an almost 3:1 
ratio of reassessment interval. For the above reasons, PHMSA is not 
proposing to expand HCAs. Instead, PHMSA is proposing to create and 
apply selected integrity management requirements to a category of 
lesser consequence areas defined as MCAs. With regard to the criteria 
for defining HCAs, PHMSA also considered several alternatives, 
including more relaxed population density and excluding small pipe 
diameters.
    In addition, a major constituency of the pipeline industry (INGAA) 
has committed to apply IM principles to all segments where any persons 
are located. This is comparable to PHMSA's proposed MCA definition. 
PHMSA seeks comment on the relative merits of expanding High 
Consequence Areas

[[Page 20733]]

versus creating a new category of ``Moderate Consequence Areas.''
    Another alternative PHMSA considered was a shorter a compliance 
deadline (10 years) and a shorter reassessment interval (15 years) for 
MCA assessments. The assessment timeframes in the proposed rule were 
selected based on a graded approach which would apply relaxed 
timeframes to MCAs, as compared to HCAs. The industry was originally 
required to perform baseline assessments for approximately 20,000 miles 
of HCA pipe within approximately 8 years from the effective date of the 
integrity management rule. PHMSA estimates that approximately 41,000 
miles of pipe would require an assessment within 15 years under this 
proposed rule, thus constituting a comparable level of effort on the 
part of industry. The maximum HCA reassessment interval is 20 years for 
low stress pipe. The 20 year interval was selected to align with the 
longest interval allowed for any HCA pipe, which is 20 years for pipe 
operating less than 30% SMYS. A reassessment interval of 15 years for 
MCAs would be shorter than the reassessment interval for some HCAs. 
PHMSA also considered that compliance with the proposed rule would be 
performed in parallel with ongoing HCA reassessments at the same time, 
thus resulting in greater demand for ILI tools and industry resources 
than during the original IM baseline assessment period. In addition, 
the proposed rule incorporates other assessment goals, including 
integrity verification, maximum allowable operating pressure (MAOP) 
verification, and material documentation, thus constituting a larger/
more costly assessment effort than originally required under IM rules. 
For the above reasons, PHMSA believes that this proposed rule would 
require full utilization or expansion of industry resources devoted to 
assessments. Therefore, PHMSA believes that compressing the timeframes 
would place unreasonably high demands on the industry's assessment 
capabilities. PHMSA also considered the possibility that placing 
burdensome demands on the industry's assessment capability might drive 
assessment costs higher. PHMSA seeks comments on the potential safety 
benefits, avoided lost gas, economic costs, and operational 
considerations involved in longer or shorter compliance periods for 
initial MCA assessment periods and re-assessment intervals.
    More generally, PHMSA seeks comment on the approach and scope of 
the proposed rule with respect to applying integrity management program 
elements to additional pipe segments not currently designated as HCA, 
including, inter alia, alternative definitions of ``Moderate 
Consequence Area'' and limits on the categories of pipeline to be 
regulated within this new area.
     Topic B--Strengthening Requirements to Implement 
Preventive and Mitigative Measures for Pipeline Segments in HCAs. The 
ANPRM requested comments regarding whether the requirements of Section 
49 CFR 192.935 for pipelines in HCAs should be more prescriptive and 
whether these requirements, or other requirements for additional 
preventive and mitigative measures, should apply to pipelines outside 
of HCAs. Section 5 of the Act requires the Secretary of Transportation 
to evaluate and report to Congress on expanding IM requirements to non-
HCA pipelines. PHMSA will further evaluate applying P&M measures to 
non-HCA areas after this evaluation is complete.
    This NPRM proposes rulemaking for amending the integrity management 
rule to add requirements for selected preventive and mitigative 
measures (internal and external corrosion control).
    Two special topics associated with preventive and mitigative 
measures, leak detection and automatic valve upgrades, were addressed 
by the NTSB and Congress. The NTSB recommended that all operators of 
natural gas transmission and distribution pipelines equip their 
supervisory control and data acquisition systems with tools to assist 
in recognizing and pinpointing the location of leaks, including line 
breaks; such tools could include a real-time leak detection system and 
appropriately spaced flow and pressure transmitters along covered 
transmission lines (recommendation P-11-10). In addition, Section 8 of 
the Act requires issuance of a report on leak detection systems used by 
operators of hazardous liquid pipelines which was completed and 
submitted to Congress in December 2012. Although that study is specific 
to hazardous liquid pipelines, its analysis and conclusions could 
influence PHMSA's approach to leak detection for gas pipelines. In 
response to the NTSB recommendations, PHMSA conducted as part of a 
larger study on pipeline leak detection technology a public workshop in 
2012. This study, among other things, examined how enhancements to 
SCADA systems can improve recognition of pipeline leak locations. 
Additionally, in 2012 PHMSA held a pipeline research forum to identify 
technological gaps, potentially including the advancement of leak 
detection methodologies. PHMSA is developing a rulemaking with respect 
to leak detection in consideration of these studies and ongoing 
research. In addition, PHMSA is focusing this rulemaking on regulations 
oriented toward preventing incidents. Leak detection (in the context of 
mitigating pipe breaks as described in NTSB P-11-10) \34\ and automatic 
valve upgrades are features that serve to mitigate the consequences of 
incidents after they occur but do not prevent them. In order to not 
delay the important requirements proposed in this NPRM, PHMSA will 
address the topic of incident mitigation later in a separate 
rulemaking. It is anticipated that advancing rulemaking to address the 
NTSB recommendations will follow assessment of the results of these 
actions.
---------------------------------------------------------------------------

    \34\ Leak detection in the context of detecting small, latent 
leaks such as leaks at fittings typical of gas distribution systems, 
and is outside the scope of the ANPRM, Topic B.
---------------------------------------------------------------------------

    PHMSA completed and submitted the valve study to congress in 
December 2012. PHMSA is developing a separate rulemaking related to the 
need for remotely or automatically controlled valves to addresses the 
NTSB recommendations and statutory requirements related to this topic 
as discussed under Topic H.
     Topic C--Modifying Repair Criteria. The ANPRM requested 
comments regarding amending the integrity management regulations by 
revising the repair criteria for pipelines in HCAs to provide greater 
assurance that injurious anomalies and defects are repaired before the 
defect can grow to a size that leads to a leak or rupture. PHMSA is 
proposing in this rule to revise the repair criteria for pipelines in 
HCAs. Revisions include repair criteria for cracks and crack-like 
defects, corrosion metal loss for defects less severe than an immediate 
condition (already included), and mechanical damage defects.
    In addition, the ANPRM requested comments regarding establishing 
repair criteria for pipeline segments located in areas that are not in 
HCAs. PHMSA is proposing rulemaking for establishing repair criteria 
for pipelines that are not in HCAs. Such repair criteria would be 
similar to the repair criteria for HCAs, with more relaxed deadlines 
for non-immediate conditions. It is acknowledged that applying repair 
criteria to pipelines that are not in HCAs is one of the factors to be 
considered in the integrity management evaluation required in the Act, 
as discussed in Topic A above.
     Topic D--Improving Requirements for Collecting, 
Validating, and Integrating Pipeline Data. The ANPRM

[[Page 20734]]

requested comments regarding whether more prescriptive requirements for 
collecting, validating, integrating, and reporting pipeline data are 
necessary. PHMSA also discussed this topic in a 2012 pipeline safety 
data workshop.
    PHMSA issued Advisory Bulletin 12-06 to remind operators of gas 
pipeline facilities to verify their records relating to operating 
specifications for maximum allowable operating pressure (MAOP) required 
by 49 CFR 192.517. On January 10, 2011, PHMSA also issued Advisory 
Bulletin 11-01, which reminded operators that if they are relying on 
the review of design, construction, inspection, testing and other 
related data to establish MAOP, they must ensure that the records used 
are reliable, traceable, verifiable, and complete. PHMSA is proposing 
in this rule to add specificity to the data integration language in the 
IM rule to establish a number of pipeline attributes that must be 
included in these analyses, by explicitly requiring that operators 
integrate analyzed information, and by requiring that data be verified 
and validated. In addition, PHMSA has determined that additional rules 
are needed to ensure that records used to establish MAOP are reliable, 
traceable, verifiable, and complete. The proposed rule would add a new 
paragraph (e) to section 192.619 to codify this requirement and to 
require that such records be retained for the life of the pipeline.
     Topic E--Making Requirements Related to the Nature and 
Application of Risk Models More Detailed. The ANPRM requested comments 
regarding making requirements related to the nature and application of 
risk models more specific to improve the usefulness of these analyses 
in informing decisions to control risks from pipelines. This NPRM 
contains proposed requirements that address this topic.
     Topic F--Strengthening Requirements for Applying Knowledge 
Gained Through the IM Program. The ANPRM requested comments regarding 
strengthening requirements related to operators' use of insights gained 
from implementation of its IM program. In this NPRM, PHMSA proposes 
detailed requirements for strengthening integrity management 
requirements for applying knowledge gained through the IM Program. 
These requirements include provisions for analyzing interacting 
threats, potential failures, and worst-case incident scenarios from 
initial failure to incident termination. Though not proposed, PHMSA 
seeks comment on whether a time period for updating aerial photography 
and patrol information should be established.
     Topic G--Strengthening Requirements on the Selection and 
Use of Assessment Methods for pipelines requiring assessment. The ANPRM 
requested comments regarding the applicability, selection, and use of 
assessment methods, including the application of existing consensus 
standards. NTSB recommendation P-11-17 related to this topic, 
recommends that all gas pipelines be upgraded to accommodate ILI tools. 
PHMSA will consider separate rulemaking for upgrading pipelines pending 
further evaluation of the issue from new data being collected in the 
annual reports.
    This NPRM proposes to strengthen requirements for the selection and 
use of assessment methods. The proposed rule would provide more 
detailed guidance for the selection of assessment methods, including 
the requirements in new Sec.  192.493 when performing an assessment 
using an in-line inspection tool. This NPRM also proposes to add more 
specific requirements for use of internal inspection tools to require 
that an operator using this method must explicitly consider 
uncertainties in reported results when identifying anomalies. In 
addition, the proposed rulemaking would add a ``spike'' hydrostatic 
pressure test, which is particularly well suited to address SCC and 
other cracking or crack-like defects, guided wave ultrasonic testing 
(GWUT), which is particularly appropriate in cases where short 
segments, such as roads or railroad crossings, are difficult to assess, 
and excavation and in situ direct examination, which is well suited to 
address crossovers and other short, easily accessible segments that are 
impractical to assess by remote technology, as allowed assessment 
methods and would revise the requirements for direct assessment to 
allow its use only if a line is not capable of inspection by internal 
inspection tools.
    The issue of selection and use of assessment methods is related to 
the statutory mandate in the Act for the Comptroller General of the 
United States to evaluate whether risk-based reassessment intervals are 
a more effective alternative. The Act requires an evaluation of 
reassessment intervals and the anomalies found in reassessments. While 
not directly addressing selection of assessment methods, the results of 
the evaluation will have an influence on the general approach for 
conducting future integrity assessments. PHMSA will consider the 
Comptroller General's evaluation when it becomes available. Additional 
rulemaking may be considered after PHMSA considers the results of the 
evaluation.
     Topic H--Valve Spacing and the Need for Remotely or 
Automatically Controlled Valves. The ANPRM requested comments regarding 
proposed changes to the requirements for sectionalizing block valves. 
In response to the NTSB recommendations, PHMSA held a public workshop 
in 2012 on pipeline valve issues, which included the need for 
additional valve installation on both natural gas and hazardous liquid 
transmission pipelines. PHMSA also included this topic in the 2012 
Pipeline Research Forum. In addition, Section 4 of the Act requires 
issuance of regulations on the use of automatic or remote-controlled 
shut-off valves, or equivalent technology, where economically, 
technically, and operationally feasible on transmission pipeline 
facilities constructed or entirely replaced after the date of the final 
rule. The Act also requires completion of a study by the Comptroller 
General of the United States on the ability of transmission pipeline 
facility operators to respond to a hazardous liquid or gas release from 
a pipeline segment located in an HCA. Separate rulemaking on this topic 
will be considered based on the results of the study.
     Topic I--Corrosion Control. The ANPRM requested comments 
regarding proposed revisions to subpart I to improve the specificity of 
existing requirements. This NPRM proposes to revise subpart I, 
including a general update to the technical requirements in appendix D 
to part 192 for cathodic protection.
     Topic J--Pipe Manufactured Using Longitudinal Weld Seams. 
In recommendation P-11-15, the NTSB recommended that PHMSA amend its 
regulations to require that any longitudinal seam in an HCA be pressure 
tested in order to consider the seam to be ``stable.'' This issue is 
addressed in Topic N. PHMSA proposes to address this issue by revising 
the integrity management requirements in Sec.  192.917(e)(3) to specify 
that longitudinal seams may not be treated as stable defects unless the 
segment has been pressure tested (and therefore would require an 
integrity assessment for seam threats). Also, PHMSA proposes to add new 
requirements for verification of maximum allowable operating pressure 
(MAOP) in new Sec.  192.624.
     Topic K--Establishing Requirements Applicable to 
Underground Gas Storage. The ANPRM requested comments regarding 
establishing requirements within part 192 applicable to underground gas 
storage in order to help assure safety of

[[Page 20735]]

underground storage and to provide a firm basis for safety regulation. 
PHMSA will consider proposing a separate rulemaking that specifically 
focuses on improving the safety of underground natural gas storage 
facilities will allow PHMSA to fully consider the impacts of incidents 
that have occurred since the close of the initial comment period. It 
will also allow the Agency to consider voluntary consensus standards 
that were developed after the close of the comment period for this 
ANPRM, and to solicit feedback from additional stakeholders and members 
of the public to inform the development of potential regulations.
     Topic L--Management of Change. The ANPRM requested 
comments regarding adding requirements for management of change to 
provide a greater degree of control over this element of pipeline risk. 
This NPRM contains proposed requirements that address this topic. 
Specifically, PHMSA proposes to revise the general applicability 
requirements in Sec.  192.13 to require each operator of an onshore gas 
transmission pipeline to develop and follow a management of change 
process, as outlined in ASME/ANSI B31.8S, section 11, that addresses 
technical, design, physical, environmental, procedural, operational, 
maintenance, and organizational changes to the pipeline or processes, 
whether permanent or temporary.
     Topic M--Quality Management Systems (QMS). The ANPRM 
requested comments regarding whether and how to impose requirements 
related to quality management systems. PHMSA will consider separate 
rulemaking for this topic.
     Topic N--Exemption of Facilities Installed Prior to the 
Regulations. The ANPRM requested comments regarding proposed changes to 
part 192 regulations that would repeal exemptions to pressure test 
requirements. The NTSB recommended that PHMSA repeal 49 CFR 192.619(c) 
and require that all gas transmission pipelines be pressure tested to 
establish MAOP (recommendation P-11-14). In addition, section 23 of the 
Act requires issuance of regulations requiring tests to confirm the 
material strength of previously untested natural gas transmission 
lines. In response to the NTSB recommendation and the Act, this NPRM 
proposes requirements for verification of maximum allowable operating 
pressure (MAOP) in accordance with new Sec.  192.624 for certain 
onshore, steel, gas transmission pipelines, including establishing and 
documenting MAOP if the pipeline MAOP was established in accordance 
with Sec.  192.619(c).
    The Act also requires verification of records to ensure they 
accurately reflect the physical and operational characteristics of the 
pipelines and to confirm the established maximum allowable operating 
pressure of the pipelines. PHMSA issued Advisory Bulletin 12-06 on May 
7, 2012 to notify operators of this required action. PHMSA has 
initiated an information collection effort to gather data needed to 
accurately characterize the quantity and location of pre-1970 gas 
transmission pipeline operating under an MAOP established by 49 CFR 
192.619(c). This NPRM proposes requirements in new Sec.  192.607 for 
certain onshore, steel, gas transmission pipelines to confirm and 
record the physical and operational characteristics of pipelines for 
which adequate records are not available.
     Topic O--Modifying the Regulation of Gas Gathering Lines. 
The ANPRM requested comments regarding modifying the regulations 
relative to gas gathering lines. The Act required several actions 
related to this topic, including: review existing regulations for 
gathering lines; provide a report to Congress; and make recommendations 
on: (1) The sufficiency of existing regulations, (2) the economic 
impacts, technical practicability, and challenges of applying existing 
federal regulations to gathering lines, and (3) subject to a risk-based 
assessment, the need to modify or revoke existing exemptions from 
Federal regulation for gas and hazardous liquid gathering lines. PHMSA 
proposes to address aspects of this topic identified before enactment 
of the Act in this NPRM. The report submitted to Congress will be 
evaluated to determine the need for any future rulemaking, specifically 
the need to apply integrity management concepts to gas gathering lines.
    In addition, on August 20, 2014, the Government Accountability 
Office (GAO) released a report (GAO Report 14-667) to address the 
increased risk posed by new gathering pipeline construction in shale 
development areas. The GAO recommended that rulemaking be pursued for 
gathering pipeline safety that addresses the risks of larger-diameter, 
higher-pressure gathering pipelines, including subjecting such 
pipelines to emergency response planning requirements that currently do 
not apply. PHMSA proposes to address this recommendation as described 
below in the ``Section-by-Section Analysis'' under Sec.  192.9.
Additional Topics
     Inspection of Pipelines Following a Severe Weather Event. 
Existing pipeline regulations prescribe requirements for surveillance 
periodically patrolling of pipeline to observe surface conditions on 
and adjacent to the transmission line right-of-way for indications of 
leaks, construction activity, and other factors affecting safety and 
operation, including unusual operating and maintenance conditions. The 
cause of the 2011 hazardous liquid pipeline accident resulting in a 
crude oil spill into the Yellowstone River near Laurel, Montana was 
scouring at the river crossing due to flooding. In this case, annual 
heavy flooding occurred in the Spring of the 2011. In late May, the 
operator shut down the pipeline for several hours to assess the state 
of the pipeline. Following the assessment, the operator restarted the 
pipeline and agreed to monitor the river area on a daily basis. On July 
1, 2011 the pipeline ruptured which resulted in the release of 1,500 
barrels of crude oil into the Yellowstone River. A second break, due to 
exposure to flood conditions, occurred several years later on the same 
pipeline led to an additional spill in the Yellowstone River. Other 
examples include Hurricane Katrina (2005) which resulted in significant 
damage to the oil and gas production structures and the San Jacinto 
flood (1994) which resulted in 8 ruptures and undermining of 29 other 
pipelines. In the context of the San Jacinto flood, ``undermining'' 
occurred when support material for the pipelines was removed due to 
erosion driven by the floodwaters. As a result, the unsupported 
pipelines were subjected to stress from the floodwaters that resulted 
in fatigue cracks in the pipe walls. Based on these examples of extreme 
weather events that did result, or could have resulted, in pipeline 
incidents, PHMSA has determined that additional regulations are needed 
to require, and establish standards for, inspection of the pipeline and 
right-of-way for ``other factors affecting safety and operation'' 
following an extreme weather event, such as a hurricane or flood, an 
earthquake, a natural disaster, or other similar event that has the 
likelihood of damage to infrastructure. The proposed rule would require 
such inspections, specify the timeframe in which such inspections 
should commence, and specify the appropriate remedial actions that must 
be taken to ensure safe pipeline operations. The new regulation would 
apply to onshore transmission pipelines and their rights-of-way.

[[Page 20736]]

     Notification for 7-Year Reassessment Interval Extension. 
Subsection 5(e) of the Act identifies a technical correction amending 
section 60109(c)(3)(B) of title 49 of the United States Code to allow 
the Secretary of Transportation to extend the 7- calendar year 
reassessment interval for an additional 6 months if the operator 
submits written notice to the Secretary with sufficient justification 
of the need for the extension. PHMSA would expect that any 
justification, at a minimum, would need to demonstrate that the 
extension does not pose a safety risk. PHMSA proposes to codify this 
statutory requirement.
     Reporting Exceedances of Maximum Allowable Operating 
Pressure. Section 23 of the Act requires operators to report to PHMSA 
each exceedance of the maximum allowable operating pressure (MAOP) that 
exceeds the margin (build-up) allowed for operation of pressure-
limiting or control devices. Implicit in Sec.  192.605 is the intent 
for operators to establish operational and maintenance controls and 
procedures to effectively preclude operation at pressures that exceed 
MAOP. PHMSA expects that operators' procedures should already address 
this aspect of operations and maintenance, as it is a long-standing, 
critical aspect of safe pipeline operations. PHMSA issued ADB 12-11 to 
address exceedances of MAOP. However, PHMSA proposes to codify this 
statutory requirement in Sec.  192.605.
     Consideration of Seismicity. Section 29 of the Act states 
that in identifying and evaluating all potential threats to each 
pipeline segment, an operator of a pipeline facility must consider the 
seismicity of the area. PHMSA proposes to codify this statutory 
requirement by adding requirements to explicitly reference seismicity 
for data gathering and integration, threat identification, and 
implementation of preventive and mitigative measures.
     Safety Regulations for In-line Inspection (ILI), Scraper, 
and Sphere Facilities. PHMSA is proposing to add explicit requirements 
for safety features on launchers and receivers associated with ILI, 
scraper and sphere facilities.
     Consensus Standards for Pipeline Assessments. The proposed 
rule would incorporate by reference industry standards for assessing 
the physical condition of in-service pipelines using in-line 
inspection, internal corrosion direct assessment, and stress corrosion 
cracking direct assessment. Periodic assessment of the condition of gas 
transmission pipelines in HCAs is required by 49 CFR 192.921 and 
192.937. The regulations provide minimal requirements for the use of 
these assessment techniques since at the time these regulations were 
established, industry standards did not exist addressing how these 
techniques should be applied. Incorporation of standards subsequently 
published by the American Petroleum Institute (API), the National 
Association of Corrosion Engineers (NACE), and the American Society of 
Nondestructive Testing (ASNT) would assure better consistency, accuracy 
and quality in pipeline assessments conducted using these techniques.

F. Integrity Verification Process Workshop

    An Integrity Verification Process (IVP) workshop was held on August 
7, 2013. At the workshop, PHMSA, the National Association of State 
Pipeline Safety Representatives and various other stakeholders 
presented information and comments were sought on a proposed IVP that 
will help address mandates set forth in Section 23, Maximum Allowable 
Operating Pressure, of the Act and the NTSB Recommendations P-11-14 
(repeal pressure test exemptions) and P-11-15 (stability of 
manufacturing and construction defects). Key aspects of the proposed 
IVP process include criteria for establishing which pipe segments would 
be subject to the IVP, technical requirements for verifying material 
properties where adequate records are not available, and technical 
requirements for re-establishing MAOP where adequate records are not 
available or the existing MAOP was established under Sec.  192.619(c). 
Comments were received from the American Gas Association, the 
Interstate Natural Gas Association of America, and other stakeholders 
addressing the draft IVP flow chart, technical concerns for 
implementing the proposed IVP, and other issues. The detailed comments 
are available under Docket No. PHMSA-2013-0119. PHMSA considered and 
incorporated the stakeholder input, as appropriate, into this NPRM, 
which proposes requirements to address the current exemptions to 
pressure test requirements, manufacturing and construction defect 
stability, verification of MAOP where records to establish MAOP are not 
available or inadequate (new Sec. Sec.  192.619(e) and 192.624), and 
verification and documentation of pipeline material for certain 
onshore, steel, gas transmission pipelines (new Sec.  192.607).

III. Analysis of Comments on the ANPRM

    In Section II of the ANPRM, PHMSA sought comments concerning the 
significance of the proposed issues to pipeline safety; whether new/
revised regulations are needed and, if so, suggestions as to what 
changes are needed; and likely costs that would be associated with 
implementing any new/revised requirements. PHMSA posed specific 
questions to solicit stakeholder input. These included questions 
related to 15 specific topic areas in two broad categories:
    1. Should IM requirements be revised and strengthened to bring more 
pipeline mileage under IM requirements and to better assure safety of 
pipeline segments in HCAs? Specific topics included:
    A. Modifying the Definition of HCA,
    B. Strengthening Requirements to Implement Preventive and 
Mitigative Measures for Pipeline Segments in HCAs,
    C. Modifying Repair Criteria,
    D. Improving Requirements for Collecting, Validating, and 
Integrating Pipeline Data,
    E. Making Requirements Related to the Nature and Application of 
Risk Models More Prescriptive,
    F. Strengthening Requirements for Applying Knowledge Gained Through 
the IM Program,
    G. Strengthening Requirements on the Selection and Use of 
Assessment Methods.
    2. Should non-IM requirements be strengthened or expanded to 
address other issues associated with pipeline system integrity. 
Specific topics included:
    H. Valve Spacing and the Need for Remotely or Automatically 
Controlled Valves,
    I. Corrosion Control,
    J. Pipe Manufactured Using Longitudinal Weld Seams,
    K. Establishing Requirements Applicable to Underground Gas Storage,
    L. Management of Change,
    M. Quality Management Systems (QMS),
    N. Exemption of Facilities Installed Prior to the Regulations,
    O. Modifying the Regulation of Gas Gathering Lines.
    PHMSA received a total of 1,463 comments; 1,080 from industry 
sources (Trade Associations/Unions, Pipeline Operators and 
Consultants); 316 comments from the public (Environmental Groups, 
Government Agencies/Municipalities, NAPSR and individual members of the 
general public); and 67 general comments not directly related to the 
ANPRM questions or categories. Commenters included:


[[Page 20737]]


 Citizen Groups
    [cir] Environmental Defense Fund (EDF)
    [cir] League of Women Voters of Pennsylvania (LWV)
    [cir] Pipeline Safety Trust (PST)
    [cir] State of Washington Citizens Advisory Committee on Pipeline 
Safety (CCOPS)
 Consultants
    [cir] Accufacts Inc.
    [cir] Oleksa and Associates, Inc.
    [cir] Thomas M. Lael
    [cir] WKM Consultancy, LLC
 Government Agencies
    [cir] California Public Utilities Commission (CPUC)
    [cir] City and County of San Francisco (CCSF)
    [cir] Federal Energy Regulatory Commission (FERC)
    [cir] Harris County Fire Marshal's Office (HCFM)
    [cir] Interstate Oil and Gas Compact Commission (IOGCC)
    [cir] Iowa Utilities Board
    [cir] Kansas Corporation Commission (KCC)
    [cir] Kansas Department of Health and Environment (KDHE)
    [cir] National Association of Pipeline Safety Representatives 
(NAPSR)
    [cir] National Transportation Safety Board (NTSB)
    [cir] Railroad Commission of Texas (TRRC)
    [cir] State of Alaska--AK Natural Gas Development Authority (AKN)
    [cir] State of Alaska Dept. of Natural Resources (AKDNR)
    [cir] Wyoming County Commissioners of Pennsylvania (WYCTY)
 Pipeline Industry
    [cir] Air Products and Chemicals, Inc.
    [cir] Alliance Pipeline
    [cir] Ameren Illinois (AmerenIL)
    [cir] Atmos Energy
    [cir] Avista Corporation
    [cir] CenterPoint Energy
    [cir] CenterPoint Energy Resources Corp.
    [cir] Chevron
    [cir] Dominion East Ohio Gas (DEOG)
    [cir] El Paso (EPPG)
    [cir] ITT Exelis Geospatial Systems
    [cir] Kern River Gas Transmission Company
    [cir] MidAmerican Energy Company
    [cir] National Fuel Gas Supply Corporation
    [cir] National Grid
    [cir] Nicor Gas
    [cir] NiSource Gas Transmission & Storage
    [cir] Northern Natural Gas
    [cir] Paiute Pipeline Company
    [cir] Panhandle Energy
    [cir] Questar Gas Company
    [cir] Questar Pipeline Company
    [cir] SCGC and SDG&E (Sempra)
    [cir] Southern Star Central Gas Pipeline, Inc.
    [cir] Southwest Gas Corporation
    [cir] Spectra Energy
    [cir] TransCanada
    [cir] TransCanada Corporation
    [cir] Waste Management, Inc
    [cir] Williams Gas Pipeline
 Municipalities
    [cir] Delaware Solid Waste Authority (DSWA)
    [cir] Iowa Association of Municipal Utilities (IAMU)
 Trade Associations
    [cir] American Gas Association (AGA)
    [cir] American Public Gas Association (APGA)
    [cir] Gas Processors Association (GPA)
    [cir] Gas Piping Technology Committee (GPTC)
    [cir] Independent Petroleum Association of America, its Cooperating 
Associations, and the American Petroleum Institute (IPAA/API)
    [cir] Interstate Natural Gas Association of America (INGAA)
    [cir] NACE International
    [cir] National Solid Waste Management Association (NSWMA)
    [cir] National Utility Locating Contractors Association (Locators)
    [cir] Oklahoma Independent Petroleum Association (OKIPA)
    [cir] Texas Oil and Gas Association (TXOGA)
    [cir] Texas Pipeline Association (TPA)
 Trade Unions
    [cir] Professional Engineers in California Government (PECG)
 31 Private Citizens

    Commenters responded to ANPRM questions, but also submitted 
comments on subjects generally related to gas pipeline safety 
regulation (but not related to an ANPRM topic) and general comments 
related to a topic but not in response to any specific question. This 
NPRM presents a summary of the comments received (similar or duplicate 
comments are consolidated). The general (no-topic) comments are 
presented first under the heading ``General Comments.'' Comments on 
each topic follow under the heading ``Comments on ANPRM Section II 
Topics on Which PHMSA Sought Comment,'' beginning with general comments 
related to the topic and then proceeding to each individual question.
General Comments
General Industry Comments
    1. A number of commenters associated with the pipeline industry 
suggested that PHMSA should defer action on the changes discussed in 
the ANPRM until the studies required by the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 are completed. They contended 
the Act presents critical issues that require priority attention. They 
believe the questions raised by Congress, and to which the studies are 
addressed, could lead to fundamental changes in how pipeline safety is 
regulated and these changes need to be understood before new rules are 
written. Several commenters also suggested PHMSA lacks the resources to 
pursue simultaneously the required studies and complicated rulemakings. 
The Railroad Commission of Texas also suggested no new requirements be 
proposed until the effects of the new Act are understood, since they 
believe that the Act will change the scope of regulatory authority and 
impose additional costs on industry and regulators.
Response
    PHMSA has placed studies and evaluations that relate to the topics 
in this proposed rulemaking on the docket. PHMSA seeks public comment 
on those reports and will consider comments before finalizing this 
rule. Other topics not addressed in this rulemaking that require 
additional study or evaluation will be addressed separately. Areas for 
safety improvement that have previously been identified and that are 
not dependent on the outcome of the required studies are also the 
subject of the proposals in this Notice.
    2. INGAA, AGA, and several pipeline operators and consultants 
commented that the ANPRM suggested that PHMSA intends to pursue 
prescriptive regulation in a number of areas. They objected to this 
approach. They prefer performance-based regulation, under which 
operators have greater flexibility in deciding how the required safety 
goal can be met, considering the specific circumstances of their 
pipeline systems. They noted that integrity management, a performance-
based approach, has greatly improved pipeline safety, and suggested 
PHMSA consider expanding the elements to be covered in an IM plan and 
providing more well-defined guidelines on how these expanded plans 
should evolve over time. They noted that implementing pipeline safety 
regulations is a complex process and implementing prescriptive 
requirements is usually inefficient. They also noted that prescriptive 
requirements tend to discourage technological advancements which can 
lead to improved means to assure safety.
Response
    PHMSA believes performance-based regulations are central to 
improving pipeline performance. In some instances, however, 
prescriptive

[[Page 20738]]

requirements may be necessary to provide the requisite improvement to 
pipeline safety performance; for example, requirements for corrosion 
control, repair conditions, and repair criteria to more specifically 
address significant corrosion issues. In these cases, the unsafe 
condition can be clearly specified, and steps necessary to remediate 
the risk are well-understood engineering practice. PHMSA is committed 
to an efficient and effective approach to pipeline safety, and using 
prescriptive regulatory requirements only where necessary.
    3. AGA, Texas Pipeline Association, Texas Oil and Gas Association, 
and a number of pipeline operators objected to the scope and pace of 
change in pipeline safety regulation. These commenters noted that the 
ANPRM covered a number of complex issues. In addition, they noted that 
pipeline operators are still implementing a number of large new 
initiatives including control room management, public awareness, 
distribution integrity management, and damage prevention. They 
commented that the industry needs time to complete implementing these 
other new regulations and PHMSA and the industry need time to evaluate 
the effect they have on pipeline safety. AGA specifically expressed 
concern that the pace of change could result in unintended adverse 
consequences. The Texas Associations suggested that any expansion of 
non-HCA regulations should address highest risks first and be 
structured to tailor requirements to different pipeline conditions 
because other approaches are likely to result in increased costs with 
little safety benefit. MidAmerican commented that the ANPRM appeared to 
be based on an incorrect assumption that there are no current 
requirements applicable to non-HCA pipe; they noted that part 192 
includes many requirements applicable to non-HCA segments and that they 
assure safety. Atmos suggested PHMSA avoid the ``one size fits all'' 
approach to pipeline safety regulations.
Response
    PHMSA understands that assimilation of change is an important 
consideration and agrees that the ANPRM covers a number of complex 
issues. Many of the more complex issues contemplated in the ANPRM, such 
as leak detection and automatic valves, will be addressed by separate 
rulemaking so that more careful and detailed analysis can be completed. 
However, PHMSA is proposing rulemaking in a number of areas to assure 
that the regulations continue to provide an adequate level of safety 
for both HCAs and non-HCAs. Additional discussion of the basis for the 
proposed rulemaking is presented in the response to comments received 
for each ANPRM topic and in Section V below (Section-by-Section 
Analysis).
    4. A number of industry commenters suggested that PHMSA exercise 
care in developing broad requirements that may be inappropriate for 
some types of pipelines. In particular, APGA noted that 
``transmission'' pipeline operated by local distribution companies is 
very different from long-distance transmission lines. They are 
typically smaller diameter, operate at lower pressures, and are often 
made of plastic. AGA and distribution pipeline operators noted that 
leaks are a routine management issue for distribution pipelines and 
those requirements appropriate to leak response for transmission 
pipelines would not be appropriate in a distribution context. The Texas 
Oil & Gas Association requested that any changes be examined for 
possible unexpected impact on gathering lines, which also differ from 
transmission pipelines.
Response
    PHMSA is aware of the varying nature of pipeline systems. One 
aspect of performance-based requirements is the ability of operators to 
customize the integrity management program so that it is appropriate to 
its circumstances.
    5. AGA and some pipeline operators noted that the ANPRM suggested 
that PHMSA intends to extrapolate hazardous liquid pipeline experience 
to gas pipelines. In particular, they expressed concern regarding the 
discussion of leak detection. They noted pin-point leak detection may 
be practical for non-compressible liquids but is not for gas.
Response
    PHMSA appreciates the significant differences between hazardous 
liquid pipelines and gas pipelines with respect to leak detection. 
PHMSA is sponsoring studies and research to address leak detection in a 
responsible way, while still being responsive to related NTSB 
recommendations. PHMSA is considering separate rulemaking for leak 
detection that will address these studies and research.
    6. Pipeline industry trade associations reported that their members 
plan to implement voluntary approaches to improve pipeline safety. 
INGAA reported it has implemented a strategy to achieve a goal of zero 
pipeline incidents. This strategy includes voluntary application of IM 
principles to non-HCA pipeline segments where people live. Their goal 
is to apply ASME/ANSI B31.8S, Managing System Integrity of Gas 
Pipelines, principles to 90 percent of people who live or work in close 
proximity to pipelines by 2020, and 100 percent by 2030. INGAA's 
strategy also includes assuring the fitness for service of pipelines 
installed before federal safety regulations were promulgated, improving 
incident response time (to less than one hour in populated areas), and 
implementing the Pipelines and Informed Planning Alliance (PIPA) 
guidelines. AGA similarly reported their intentions to address 
improvements to safety proactively by applying Operator Qualification 
to new construction, continuing to advance IM principles (including 
developing industry guidelines for data management and data quality), 
and working with a coalition of PIPA stakeholders to adopt PIPA-
recommended best practices, among other initiatives.
Response
    PHMSA commends the pipeline industry for these initiatives and is 
committed to working with the industry to improve performance toward 
the goal of zero pipeline incidents.
    7. A number of comments addressed the cost-benefit analyses that 
will be required in support of rulemaking that results from this ANPRM. 
AGA noted that a detailed estimate has not been completed but that 
preliminary evaluations suggest that the cost of implementing the 
initiatives included in the ANPRM could well exceed the cost of 
implementing the 2003 gas transmission IM rule. APGA agreed that some 
of the concepts discussed in the ANPRM are potentially very costly and 
must be considered carefully. Accufacts cautioned PHMSA to be wary of 
efforts to distort the cost-benefit analyses by hyper inflating costs. 
As an example, Accufacts pointed to estimates of costs to perform 
hydrostatic tests ranging from $500,000 to $1,000,000 per mile compared 
to costs of $29,400 to $40,000 per mile cited in the NTSB report on the 
San Bruno accident.
Response
    PHMSA acknowledges that estimates of hydrostatic test costs can 
vary and that there is risk in using overstated estimates in the 
analysis of benefits and costs since regulatory decisions regarding 
public safety can be based on these results. For the Preliminary 
Regulatory Impact Assessment (PRIA) for this proposed rule PHMSA used 
vendor pricing data to develop unit costs for pressure testing. These 
costs represent the contractor's costs to complete an eight hour 
pressure test for

[[Page 20739]]

various segment diameters and lengths. PHMSA applied a multiplier to 
account for other operator costs, such as manifold installation and 
operational oversight, and also added estimated costs to provide 
temporary gas supplies and the market value of lost gas. Based on these 
data and assumptions, PHMSA estimated per mile pressure test costs 
range from approximately $60,000 per mile (12'' diameter, 10 mile 
segment) to 630,000 (36'' diameter, one mile segment). Detailed 
explanations of these unit costs are available in the PRIA, provided in 
the regulatory docket.
    8. AGA and several pipeline operators suggested PHMSA should 
establish jointly with industry a committee to evaluate pipeline data 
and to determine whether more data is needed. They commented industry 
has repeatedly made this request and PHMSA has, to date, not responded. 
They contended PHMSA's current analysis of pipeline safety performance 
data is inadequate. Similarly, Panhandle Energy noted a number of the 
questions in the ANPRM requested data on various subjects; Panhandle 
expressed its belief that PHMSA collects and has access to at least 
some of data requested, and this data, collected pursuant to regulatory 
requirements, should be more complete, and consistently collected and 
reported, than piecemeal collections of data in response to this ANPRM. 
Expressing a somewhat contrary view, El Paso suggested more data should 
be collected and analyzed before notices of proposed rulemakings are 
prepared; PHMSA needs to collect and analyze data to determine the 
proper path for future requirements, if any.
Response
    In response to NTSB recommendation P-11-19, PHMSA held a pipeline 
safety data workshop in January 2013. The workshop: (1) Summarized the 
data OPS collects, who it is collected from, and why it is collected; 
(2) addressed how stakeholders, including OPS, industry, and the public 
use the data; (3) addressed data quality improvement efforts and 
performance measures; and (4) discussed the best method(s) for 
collecting, analyzing, and ensuring transparency of additional data 
needed to improve performance measures. PHMSA considered the results of 
the workshop as well as the comments to the ANPRM related to pipeline 
safety performance data.
    9. APGA suggested PHMSA revise the definitions of transmission and 
distribution pipelines to be more risk-based. APGA contended that the 
current definitions are not risk-based and lead to inappropriate 
outcomes. In particular, classification of some pipelines as 
``transmission'' based on functional aspects of the current definition 
leads to inappropriate application of requirements. In a similar vein, 
Oleksa and Associates suggested it may be time to reduce IM 
requirements on low-stress transmission pipelines, which pose lower 
risk than high-stress lines. Texas Pipeline Association and Texas Oil & 
Gas Association commented PHMSA should not extrapolate experience with 
interstate pipelines to intrastate lines, which differ in design and 
operation.
Response
    The definition of transmission vs. distribution pipelines and the 
applicability requirements for integrity management in High Consequence 
Areas is not within the scope of this proposed rule. The general topic 
of the scope and applicability of integrity management is addressed in 
the class location report which available in the docket.
    10. Northern Natural Gas recommended all exemptions from one-call 
requirements be eliminated. They noted excavation damage remains, by 
far, the single greatest threat to pipeline safety and management of 
excavation damage, through one-call programs, has been demonstrated to 
be an effective means of countering that threat.
Response
    This comment is not within the scope of the ANPRM topics. However, 
PHMSA has revised the pipeline safety regulations related to pipeline 
damage prevention programs, which includes one-call programs, in an 
final rule issued July 23, 2015 (80 FR 43836).
    11. The Gas Processors Association, Texas Pipeline Association, and 
Texas Oil & Gas Association commented regarding current efforts to 
clarify the applicability of part 192 requirements, particularly 
requirements for distribution integrity management, to farm taps. They 
suggested PHMSA is engaged in an expansion of requirements in this area 
without notice or a demonstrated safety need. They suggested PHMSA 
initiate a rulemaking specifically to clarify requirements applicable 
to farm taps.
Response
    Treatment of farm taps is not within the scope of the ANPRM topics. 
However, PHMSA has engaged in dialogue with industry on this topic and 
will continue to consider options to address this issue in a separate 
action.
    12. Northern Natural Gas suggested PHMSA reduce the time allowed 
for conducting a baseline assessment in cases where a new HCA is found, 
tailored to the circumstances of the particular segment. Northern 
expressed its belief this would address threats to integrity in areas 
affecting population more quickly than current requirements.
Response
    Currently, Sec.  192.905(c) requires that newly identified HCAs be 
incorporated into the baseline assessment plan within one year. PHMSA 
does not currently have plans to address this requirement. However, 
periodically DOT or PHMSA seeks public input on retrospective review of 
existing regulations under Executive Order 13563. PHMSA encourages the 
commenter to raise this issue the next time DOT or PHMSA solicits 
comments on retrospective review of existing regulations.
    13. Alliance Pipeline suggested many pipeline safety questions can 
be answered by applying INGAA's five guiding principles of pipeline 
safety. They noted INGAA has developed the Integrity Management-
Continuous Improvement (IMCI) Initiative to implement these principles 
and suggested PHMSA actively engage with INGAA in developing workable 
solutions to pipeline safety issues.
Response
    PHMSA appreciates the industry efforts to improve pipeline safety 
and is committed to working with all stakeholders toward this end.
    14. Paiute Pipeline and Southwest Gas commented integrity 
management requirements have not been in effect long enough to gauge 
their effectiveness and decide whether additional changes are needed. 
The companies noted the first, baseline assessments of pipeline 
segments subject to those requirements are only now being completed. 
AGA and other pipeline operators agreed, noting IM is still new, 
operators are still refining their processes, and PHMSA should approach 
change with caution.
Response
    While the first round of baseline assessments are only now being 
completed, the gas IM rule has been in place approximately 10 years. 
PHMSA expects that operator IM programs should have significantly 
matured in this timeframe.
    15. Panhandle Energy suggested that PHMSA evaluate rule changes 
that could have prevented incidents which occurred in recent years. Any 
initiatives that would not have contributed to improved safety, they 
suggest, should be postponed or treated as lower priority activities. 
Panhandle suggested rulemaking without a sound basis is not

[[Page 20740]]

only ineffective but counterproductive in that it diverts resources 
that could have been used to improve safety. Questar Gas similarly 
commented PHMSA needs to minimize unnecessary activities that 
inappropriately divert safety resources. Questar also recommended that 
PHMSA explicitly consider the diversity within the regulated community.
Response
    One of the major motivations for PHMSA's issuance of the ANPRM was 
to solicit information useful to ensuring that pipeline safety reforms 
have a sound basis. PHMSA is also required by Executive Orders 12866 
and 13563 to ensure that the benefits of its rules justify the costs, 
to the extent permitted by law. PHMSA has prepared an initial 
regulatory impact analysis for this proposed rule, which is available 
in the docket for this rule. PHMSA encourages the commenter as well as 
other members of the public to review the analysis and provide input 
for improving the final rule.
    16. AGA and several pipeline operators commented that, while 
enhancements can be made, IM requirements need not be subjected to 
wholesale change. They cited GAO and NTSB reports on the efficacy of 
transmission pipeline integrity management and the lack of pipeline 
safety issues among the NTSB's ``Most Wanted'' issues.
Response
    While PHMSA believes that IM has led to improvements in managing 
pipeline integrity, recent incidents and accidents demonstrate that 
much work remains to improve pipeline safety.
    17. AGA and pipeline operators noted that transmission and 
distribution integrity management are not distinct activities for most 
intrastate pipeline operators. They contended that the ANPRM seemed to 
be based on a presumption that operators manage their transmission and 
distribution pipeline safety differently, and that this assumption is 
without basis.
Response
    PHMSA has promulgated specific IM rules for both transmission and 
distribution systems with a view toward allowing operators to customize 
their performance based programs as appropriate to their specific 
systems.
    18. AGA and several pipeline operators suggested that any changes 
to public awareness requirements should be made at the state level. 
They noted that federal requirements in this area are new and that 
effectiveness reviews are still in progress.
Response
    This issue is not within the scope of the ANPRM. However, PHMSA has 
revised the pipeline safety regulations related to pipeline damage 
prevention programs in a final rule issued July 23, 2015 (80 FR 43836).
    19. NACE International suggested that adopting its standards for 
corrosion control would be the best means to accomplish the goal of 
maintaining pipelines safe and functional for long periods of time.
Response
    This NPRM proposes to incorporate industry consensus standards into 
the regulations for assessing the physical condition of in-service 
pipelines using in-line inspection, internal corrosion direct 
assessment, and stress corrosion cracking direct assessment. In 
addition, this NPRM proposes to enhance subpart I requirements for 
corrosion control and to revise Appendix D to improve requirements for 
cathodic protection.
    20. The NTSB commented that regulations for gas transmission 
pipelines can and should be improved and expressed its support for the 
overall intent of the ANPRM. The NTSB noted publication of the ANPRM 
prior to its recommendations resulting from the San Bruno incident 
investigation precluded any mention in the ANPRM of these NTSB safety 
recommendations. The NTSB suggested PHMSA should seek comment on its 
recommendations.
Response
    PHMSA has reviewed the NTSB recommendations that were issued on 
September 26, 2011 and found that several recommendations related 
directly to the topics addressed in the ANPRM and that may impact the 
proposed approach to rulemaking. The topics impacted are discussed 
above in the Background section above, in sections II.C and II.E, and 
include NTSB Recommendations P-11-10, P-11-11, P-11-14, P-11-15, P-11-
17, and P-11-19. The NTSB's other recommendations will be addressed in 
separate proceedings.
    21. El Paso suggested that the proper approach to attain the 
highest pipeline safety levels is through a structured, deliberate 
rulemaking that closely examines all issue aspects prior to making 
informed decisions.
Response
    PHMSA agrees and is taking a careful, structured, and phased 
approach to enhancing pipeline safety regulations and IM performance 
standards.
    22. Thomas M. Lael, a pipeline industry consultant, suggested any 
new regulations be concise and clear. He contended past lack of clarity 
has created the need for many re-interpretations and enforcement 
problems.
Response
    PHMSA concurs but also notes that performance-based regulations, by 
their nature, are not as specific, nor as easily measurable, as 
prescriptive regulations, but are more likely to improve safety and the 
cost-effectiveness of regulations. PHMSA provides guidance to help 
stakeholders understand the intent and scope of performance-based 
regulations.
General Public Comments
    1. A member of the public stated that the ANPRM did not provide 
specific options for consideration. As written, only those with direct 
involvement in the industry could understand it well enough to comment. 
Presenting the options more specifically would allow for better 
informed public comment. The discussion should also include a regional 
component, since issues affecting different states/regions are not the 
same.
Response
    By its nature, the ANPRM did not propose specific alternatives or 
rules, but solicited input to help inform future proposals. This NPRM 
provides specific proposed rules for public comment.
    2. The Alaska Natural Gas Development Authority stated that the 
regulations should require consideration of earthquakes, as recent 
history shows they can be very important to safety of high-pressure gas 
lines.
Response
    Section 29 of the Act states that in identifying and evaluating all 
potential threats to each pipeline segment, an operator of a pipeline 
facility shall consider the seismicity of the area. Rulemaking for this 
issue is addressed in this NPRM and would add requirements to 
explicitly reference seismicity for data gathering and integration, 
threat identification and implementation of preventive and mitigative 
measures.
    3. The Environmental Defense Fund pointed out that methane is a 
very potent greenhouse gas. They commented that PHMSA should consider 
and minimize the potential environmental effects of any future 
rulemaking. They suggested EPA's Natural Gas Star program as a model.

[[Page 20741]]

Response
    The proposals in this rulemaking are designed to minimize the risk 
of pipeline failures, which will result in environmental benefits. The 
draft environmental assessment addresses the environmental effects of 
this rulemaking.
    In addition, the RIA provides estimates of the environmental 
benefits of this proposed rule. Natural gas transported in transmission 
pipelines contains heat-trapping gases that contribute to global 
climate change and its attendant societal costs. Of these gases, of 
primary importance for evaluation are methane--by far, the largest 
constituent of natural gas--and carbon dioxide. Other natural gas 
components (ethane, propane, etc.) contribute as well, but they account 
for a much smaller percentage of the natural gas mixture and, as a 
result, are much less significant than methane in terms of their 
environmental impact. The proposed rule is expected to prevent 
incidents, leaks, and other types of failures that might occur, thereby 
preventing future releases of greenhouse gases (GHG) to the atmosphere, 
thus avoiding additional contributions to global climate change. PHMSA 
estimated net GHG emissions abatement over 15 years of 69,000 to 
122,000 metric tons of methane and 14,000 to 22,000 metric tons of 
carbon dioxide, based on the estimated number of incidents averted and 
emissions from pressure tests and ILI upgrades.
    4. A member of the public questioned the openness and clarity of 
PHMSA's enforcement of pipeline safety regulations, and the use of 
civil penalty revenues.
Response
    This comment is not within the scope of the ANPRM topics, however, 
it should be noted that PHMSA embraces transparency in its regulatory 
oversight program and has established a Pipeline Safety Stakeholder 
Communications Web site, http://primis.phmsa.dot.gov/comm/, which 
presents a variety of reports detailing enforcement activity. These 
reports are offered on both nationwide and operator-specific bases.
    5. One member of the public suggested that DOT define ``safe 
corridors'' for above-ground construction of pipelines. The commenter 
suggested this would be similar, in principle, to the interstate 
highway system. It would help to keep pipelines separated from 
residences, avoid corrosive environments, and make pipelines available 
for routine direct examination. At a minimum, this commenter suggested 
the regulations should specify a minimum separation between new 
pipelines and residences, as does the New Jersey state code, or 
homebuyers be informed when a home is within the potential impact 
radius of a gas transmission pipeline so they may make an informed 
buying decision.
Response
    This comment addresses pipeline siting and routing, which is 
outside the scope of PHMSA's statutory authority. As specified in 49 
U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is 
prohibited from regulating activities associated with locating and 
routing pipelines. Paragraph (e) of the statute states ``Location and 
routing of facilities.--This chapter does not authorize the Secretary 
of Transportation to prescribe the location or routing of a pipeline 
facility.'' However, PHMSA is an active participant in the Pipeline and 
Informed Planning Alliance (PIPA) and encourages all stakeholders to 
learn about, and become involved with, PIPA. More information can be 
obtained online at: http://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm.
    6. One member of the public noted there is an increasing trend in 
significant incidents and suggested that this trend may be related to 
undue influence of the pipeline industry on the regulations under which 
it operates. The commenter recommended regulations should not be 
weakened in favor of industry. The League of Women Voters of 
Pennsylvania also recommended that regulatory agencies be insulated 
from political and other influences of natural gas pipeline companies 
to avoid the appearance of a conflict of interest.
Response
    PHMSA appreciates these comments. PHMSA is committed to improving 
pipeline safety, and that is the goal of this endeavor. Significant 
incidents on Gas Transmission (GT) pipelines have averaged between 70 
and 80 incidents per year over the past 9 years. The existing integrity 
management regulations in 49 CFR part 192, subpart O, addresses 
pipeline integrity in HCAs, which is only about 7 percent of the GT 
pipeline mileage. This proposed NPRM is focused on strengthening 
requirements in HCAs and applying integrity management principles to 
areas outside HCAs to better address safety issues. In addition, the 
proposed rule seeks to address significant issues that caused or 
contributed to the San Bruno accident, which include lack of pressure 
test, inadequate records, poor materials, and inadequate integrity 
assessment. The operator reports submitted to PHMSA as mandated by the 
Act confirm that these issues are widespread for both HCA and non-HCA 
pipe segments.
    7. The Harris County Fire Marshall's Office (HCFM) suggested 
stiffer regulations are needed for gas transmission pipeline safety, 
because of the large potential for negative impact and catastrophic 
consequences. HCFM expressed concern about corrosion control and 
current inspection practices for aging transmission infrastructure.
Response
    This NPRM proposes enhanced corrosion control requirements, 
including periodic close interval surveys, post construction surveys 
for coating damage, and interference current surveys. This NPRM also 
proposes enhanced requirements for internal corrosion and external 
corrosion management programs.
    8. The Pipeline Safety Trust (PST) commented that the ANPRM, 
itself, may heighten and fuel existing public concerns about pipeline 
safety. PST noted that many of the questions asked the industry to 
provide information they believe the public would believe PHMSA should 
already have. PST expressed its view that the number and types of 
questions asked in the ANPRM reflect gaps in PHMSA's knowledge of gas 
transmission pipeline systems and operator practices.
Response
    PHMSA appreciates these comments. PHMSA is committed to improving 
pipeline safety and stakeholder input is valuable to the regulatory 
process.
    9. Professional Engineers in California Government (PECG) commented 
that private companies should not be solely responsible for the safety 
of their pipelines. PECG contended that this approach has not worked. 
PECG also suggested PHMSA examine options for increasing the number of 
inspectors at state pipeline regulatory agencies and require public 
inspectors be on site for pipeline construction and testing. They 
contended such inspection is necessary to assure that older pipelines 
are tested adequately and replaced when needed.
Response
    PHMSA appreciates these comments. PHMSA is committed to ensuring 
that operators maintain and operate their pipelines safely. This 
rulemaking contains a number of measures aimed at enhancing oversight.
    10. The City and County of San Francisco (CCSF) noted the scope of 
potential rulemaking discussed in the

[[Page 20742]]

ANPRM did not include consideration of PHMSA's coordination with and 
oversight of state certified agencies. In order to ensure the proper 
oversight over natural gas transmission operators and the safe 
operation of natural gas transmission lines, CCSF believes PHMSA must 
address its state certification program and its oversight of state 
enforcement of pipeline safety standards. CCSF recommended PHMSA 
publish regulations for certification of state programs. They cited 
NTSB recommendation P-11-20 and asserted PHMSA has not corrected 
inadequate practices of the California Public Utilities Commission.
Response
    This comment is outside the scope of this rulemaking. PHMSA is 
addressing NTSB recommendation P-11-20 separately.
    11. Two members of the public suggested the processes of the 
Federal Energy Regulatory Commission (FERC) for siting pipelines should 
be revised. One suggested a Commission on Public Accountability and 
Safety Standards be established, consisting of a majority of local 
public officials, first responder experts, and independent qualified 
engineers, to make recommendations for FERC's pre-application process 
and standards. The purpose would be to assure standards require public 
accountability for review and vetting of pipeline safety issues with 
local authorities when pipelines are proposed. The other commenter 
suggested the relationship between FERC and DOT should be clarified, 
that a company's enforcement history be taken into account in siting 
decisions, and PHMSA be a full party to all FERC proceedings. The 
commenter believes this is necessary because FERC does not have a 
public safety mandate.
Response
    PHMSA is a separate agency from FERC and has no statutory authority 
with respect to pipeline siting or approval. As specified in 49 U.S.C. 
60104, Requirements and Limitations of the Act, PHMSA is prohibited 
from regulating activities associated with locating and routing 
pipelines. Paragraph (e) of the statute states ``Location and routing 
of facilities.--This chapter does not authorize the Secretary of 
Transportation to prescribe the location or routing of a pipeline 
facility.'' However, PHMSA is an active participant in the Pipeline and 
Informed Planning Alliance (PIPA) and encourages all stakeholders to 
learn about, and become involved with, PIPA. More information can be 
obtained online at: http://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm.
    12. Two members of the public commented federal regulations should 
not override local ordinances. They noted the concern of local 
authorities is safety, while others are concerned about industry costs. 
They believe federal regulations that allow operators significant 
discretion are a poor basis to supersede specific local requirements.
Response
    PHMSA appreciates these comments. Federal regulations provide for a 
uniform body of standards and requirements related to pipeline safety. 
PHMSA is receptive to input from state and local authorities on 
pipeline safety issues. States and local authorities may adopt 
requirements that are more stringent than and consistent with the 
federal regulations for their intrastate pipelines if they have a 49 
U.S.C. 60105 certification.
    13. One member of the public suggested regulations require periodic 
safety audits by an auditor not selected by the pipeline operator. The 
commenter further suggested that local authorities should have approval 
authority in the choice of the auditor. The commenter contended this 
approach would strengthen public confidence in pipeline safety.
Response
    PHMSA appreciates this comment. Highly trained federal and state 
pipeline inspectors conduct inspections of pipeline operators, their 
facilities, and their compliance programs on a regular basis.
Comments on ANPRM Section II Topics on Which PHMSA Sought Comment
    In section II of the ANPRM, commenters were urged to consider 
whether additional safety measures are necessary to increase the level 
of safety for those pipelines that are in non-HCA areas as well as 
whether the current IM requirements need to be clarified and in some 
cases enhanced to assure that they continue to provide an adequate 
level of safety in HCAs. PHMSA posed specific questions to solicit 
stakeholder input. These included questions related to the following 
topics:
    A. Modifying the Definition of HCA,
    B. Strengthening Requirements to Implement Preventive and 
Mitigative Measures for Pipeline Segments in HCAs,
    C. Modifying Repair Criteria,
    D. Improving Requirements for Collecting, Validating, and 
Integrating Pipeline Data,
    E. Making requirements Related to the Nature and Application of 
Risk Models More Prescriptive,
    F. Strengthening Requirements for Applying Knowledge Gained Through 
the IM Program
    G. Strengthening Requirements on the Selection and Use of 
Assessment Methods,
    H. Valve Spacing and the Need for Remotely or Automatically 
Controlled Valves,
    I. Corrosion Control,
    J. Pipe Manufactured Using Longitudinal Weld Seams,
    K. Establishing Requirements Applicable to Underground Gas Storage,
    L. Management of Change,
    M. Quality Management Systems (QMS),
    N. Exemption of Facilities Installed Prior to the Regulations,
    O. Modifying the Regulation of Gas Gathering Lines.
    Each topic is summarized as presented in the ANPRM, then general 
comments related to the topic are presented, followed by each 
individual question and comments received for the question.

A. Modifying the Definition of HCA

    The ANPRM stated that ``IM requirements in subpart O of part 192 
specify how pipeline operators must identify, prioritize, assess, 
evaluate, repair and validate; [sic] through comprehensive analyses, 
the integrity of gas transmission pipelines in HCAs. Although operators 
may voluntarily apply IM practices to pipeline segments that are not in 
HCAs, the regulations do not require operators to do so. A gas 
transmission pipeline ruptured in San Bruno, California on September 9, 
2010, resulting in eight deaths and considerable property damage. As a 
result of this event, public concern has been raised regarding whether 
safety requirements applicable to pipe in populated areas can be 
improved. PHMSA is thus considering expanding the definition of an HCA 
so that more miles of pipe are subject to IM requirements.'' The ANPRM 
then listed questions for consideration and comment. The following are 
general comments received related to the topic as well as comments 
related to the specific questions:
General Comments for Topic A
    1. INGAA and a number of pipeline operators noted this is an 
opportune time for considering the next steps in integrity management, 
since baseline assessments under the current IM rules are now being 
completed. INGAA noted its policy goal is to apply IM principles

[[Page 20743]]

(as described in ASME/ANSI B31.8S) beyond HCAs, covering 90 percent of 
people living near transmission pipelines by 2020 and 100 percent by 
2030. TransCanada submitted information in support of INGAA's proposal, 
noting that by the end of 2012 the company will have assessed more than 
85 percent of its US pipeline mileage covering more than 95 percent of 
people living near their pipelines. Thus, the current IM rules are 
having a significant positive impact on pipeline safety. TransCanada 
believes significant technological challenges would be encountered if 
IM regulations were extended to all pipelines.
    2. MidAmerican commented it would be reasonable to differentiate 
between transmission pipelines operating above and below 30 percent 
specified minimum yield strength (SMYS) in terms of IM requirements. 
They estimated that less than 3 percent of local distribution company 
(LDC) transmission lines operate at greater than 30 percent SMYS.
    3. MidAmerican and a member of the public suggested PHMSA eliminate 
class locations in favor of better-defined HCAs. They contend such a 
change would result in administrative savings for pipeline operators.
    4. Southwest Gas and Paiute commented no new regulations should be 
promulgated in this area until the study required by the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011 is 
completed.
Response to General Comments for Topic A
    PHMSA appreciates the information provided by the commenters. 
Section 5 of the Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011 (the Act) (Pub. L. 112-90) requires the Secretary 
of Transportation to ``evaluate (1) whether integrity management system 
requirements, or elements thereof, should be expanded beyond high-
consequence areas; and (2) with respect to gas transmission pipeline 
facilities, whether applying integrity management program requirements, 
or elements thereof, to additional areas would mitigate the need for 
class location requirements.'' PHMSA has completed the report mandated 
by the Act that documents that evaluation and addresses whether 
integrity management (IM) program requirements should be expanded 
beyond high consequence areas (HCAs) and, specifically for gas 
transmission pipelines regulated under 49 Code of Federal Regulations 
(CFR) part 192, whether such expansion would mitigate the need for 
class location designations and corresponding requirements. The class 
location report is available for review in the docket.
    In October 2010 and August 2011, the Pipeline and Hazardous 
Materials Safety Administration (PHMSA) published notices in the 
Federal Register to solicit comments on revising the pipeline safety 
regulations applicable to hazardous liquid and natural gas transmission 
pipelines including expansion of IM program requirements beyond HCAs. 
In general, industry representatives and pipeline operators were 
opposed to any expansion of HCAs and in favor of eliminating class 
locations on newly constructed pipelines, whereas public interest 
groups were in favor of expanding HCA but against curtailing class 
location requirements.
    PHMSA has carefully considered the input and comments. At this time 
PHMSA plans to propose an approach that balances the need to provide 
additional protections for persons within the potential impact radius 
(PIR) of a pipeline rupture (outside of a defined HCA), and the need to 
prudently apply IM resources in a fashion that continues to emphasize 
the risk priority of HCAs. PHMSA, therefore, is considering an approach 
that would require selected aspects of IM programs (namely, integrity 
assessments and repair criteria) to be applicable for non-HCA segments. 
For hazardous liquid pipelines, PHMSA would propose to apply these 
requirements to non-HCA pipeline segments. For gas transmission 
pipelines, PHMSA would propose to apply these requirements where 
persons live and work and could reasonably be expected to be located 
within a pipeline PIR. Under this approach, PHMSA would propose 
requirements that integrity assessments be conducted, and that 
injurious anomalies and defects be repaired in a timely manner, using 
similar standards in place for HCAs. However, the other program 
elements of a full IM program contained in 49 CFR part 192, subpart O, 
or 49 CFR 195.452 (as applicable) would not be required for non-HCA 
segments.
    The Act also required the Secretary of Transportation to evaluate 
if expanding IM outside of HCAs, as discussed above, would mitigate the 
need for class location requirements. In August 2013, PHMSA published a 
notice in the Federal Register (78 FR 53086) soliciting comments on 
expanding IM program requirements and mitigating class location 
requirements. In addition, PHMSA held a Class Location Workshop on 
April 16, 2014, to discuss the notice and comments were received from 
stakeholders, including industry representatives, pipeline operators, 
state regulatory agencies, and the public. Overall, the majority of 
stakeholder responses suggested that PHMSA not change the current class 
location approach for class locations and class location changes as 
population increases used for establishing MAOP and operation and 
maintenance (O&M) surveys for existing pipelines. For new transmission 
pipelines, some industry groups and operators supported some type of 
bifurcated approach for existing and new pipelines as described above.
    Based upon stakeholder input and findings from lessons learned, 
incident investigations, assessments, IM, and operating, maintenance, 
design and construction considerations, PHMSA believes the application 
of integrity management assessment and remediation requirements to MCAs 
does not warrant elimination of class locations. Class locations affect 
all gas pipelines, including transmission (interstate and intrastate), 
gathering, and distribution pipelines, whether they are constructed of 
steel pipe or plastic pipe. Class location is integral to determining 
MAOPs, design pressures, pipeline repairs, high consequence areas 
(HCAs), and operating and maintenance inspections and surveillance 
intervals. Class locations affect 12 subparts and 28 sections of 49 CFR 
part 192 for gas pipelines. The subparts and sections are listed and 
discussed in Sections 3.1.2.4 and 3.7.2.2. While assessment and 
remediation of defects on gas transmission pipelines is an important 
risk mitigation program, it does not adequately compensate for other 
aspects of class location as it relates to other types of gas pipelines 
and as it relates (for all gas pipelines) to the original pipeline 
design and construction such as the design factor, initial pressure 
testing, establishment of MAOP, O&M activities, and other aspects of 
pipeline safety, that are based on class location. Thus, PHMSA has 
determined not to eliminate class location requirements.
    With respect to the application of gas transmission IM requirements 
to pipeline operating at less than 30% SMYS, as part of its 
consideration of the issues discussed in Topics J and N, PHMSA 
considered but rejected the suggestion that pipelines operating less 
than 30% SMYS be differentiated from those operating at higher stress 
levels.
    Comments submitted for questions in Topic A.
    A.1--Should PHMSA revise the existing criteria for identifying HCAs 
to expand the miles of pipeline included in HCAs? If so, what 
amendments to the criteria should PHMSA consider (e.g.,

[[Page 20744]]

increasing the number of buildings intended for human occupancy in 
Method 2?) Have improvements in assessment technology during the past 
few years led to changes in the cost of assessing pipelines? Given that 
most non-HCA mileage is already subjected to in-line inspection (ILI), 
does the contemplated expansion of HCAs represent any additional cost 
for conducting integrity assessments? If so, what are those costs? How 
would amendments to the current criteria impact state and local 
governments and other entities?
    1. INGAA, industry consultant Thomas Lael, and a number of pipeline 
operators commented that modification of the HCA definition is 
unnecessary. They contended that the current definition is already 
risk-based and provides an effective basis for IM requirements along 
with a reasonable point from which to expand the application of IM 
principles by voluntary action. Accufacts commented that PHMSA should 
focus on closing gaps and loopholes rather than increasing HCA mileage, 
and that increasing covered mileage would only create the illusion of 
more safety.
    2. AGA, APGA, and a number of gas distribution pipeline operators 
also opposed changes to the definition. They commented that other 
requirements of part 192 already address the primary threats for pipe 
outside HCA. They noted that much effort went into establishing the 
current definition, there is no safety rationale to abandon it, and 
change would be inconsistent with risk-based principles and would 
dilute safety efforts. AGA further noted that imprudent expansion would 
be contrary to Congressional intent, in that it would dilute the focus 
on densely populated and environmentally sensitive areas. AGA commented 
that PHMSA should make no change in this area before completing the 
related studies required by the Pipeline Safety, Regulatory Certainty, 
and Job Creation Act of 2011.
    3. Taking a contrary position, a number of commenters not 
affiliated with the pipeline industry supported increasing the pipeline 
mileage classified as HCA. One private citizen suggested that all 
pipelines in cities with population greater than 100,000 should be 
classified as HCA. This commenter believes that existing regulations 
result in insufficient requirements for urban pipelines. Another 
citizen suggested that all high-stress lines with a ``receptor,'' which 
he defines as ``something which needs to be protected,'' should be 
assessed. If changes to the HCA definition are needed to accomplish 
this, then he contended those changes should be made. The Pipeline 
Safety Trust would strengthen IM requirements and expand them to all 
transmission pipelines, although they allow that the details could be 
different for pipelines not currently classified as HCA. PST believes 
this would be an effective way to identify and eliminate threats.
    4. The Oklahoma Independent Petroleum Association (OKIPA) commented 
that any changes to the HCA definition must be supported by a 
scientifically-valid assessment of risks and a complete cost-benefit 
analysis.
    5. The Iowa Association of Municipal Utilities commented that PHMSA 
should not revise the HCA definition without taking into account the 
differences between high-pressure transmission pipelines and low-
pressure, low-risk lines that are also classified as transmission. IAMU 
reported ``transmission lines'' operated by Iowa Municipal Utilities 
are typically 2 to 4 inches in diameter and have potential impact radii 
less than 90 feet.
    6. The Texas Pipeline Association and Texas Oil & Gas Association 
contended that expanding HCA pipeline mileage would increase assessment 
costs, particularly if the arbitrary requirement for reassessments 
every 7 years is not changed. These associations also believe that 
additional assessments will result in significant service 
interruptions. They suggested that assessment requirements be expanded 
to other pipelines, if needed, rather than changing the definition of 
HCA, contending that this would allow a more reasoned approach not 
burdened by the requirement for 7-year reassessments.
    7. The Texas Pipeline Association, Texas Oil & Gas Association and 
several pipeline operators disagreed with the ANPRM assertion that most 
non-HCA transmission pipeline has been subject to ILI inspections. They 
noted much non-HCA pipeline has been pigged (i.e., assessed using an 
in-line inspection tool) but that intrastate transmission pipelines are 
typically not piggable.
    8. MidAmerican suggested that there is no reason to believe that 
changes to the HCA definition would improve safety. They also noted 
that the effects of other recent regulatory changes have not yet been 
realized and could mask any effect of changes in HCA. At the same time, 
the company noted that revising the definition of an HCA to encompass 
potential impact circles with 15 structures intended for human 
occupancy, vs. the current 20, would increase the amount of HCA mileage 
on its pipeline system by about 10 percent, contending that the safety 
benefit of such a change would be questionable. They suggested it would 
be better to focus on pipe in HCAs rather than adding lower-risk pipe, 
since part 192 already provides a good level of safety for all 
pipelines.
    9. INGAA and a number of pipeline operators commented that 
increasing the amount of HCA mileage would add or increase costs for 
hundreds of state and local government agencies. The increases would 
result from increased demands for identification, certification, and 
compliance auditing.
    10. Northern Natural Gas suggested that PHMSA consider expanding 
HCA coverage by modifying the specifics of Method 2 for defining HCAs 
over time. Changes could include reducing the number of structures in 
potential impact circles that define an HCA, reducing the number of 
people that defines an identified site, etc. The company believes this 
kind of change would have the benefit of continued use of the 
``science'' represented by the C-FER Technologies circle for 
determining HCAs (see part 192, appendix E, figure E.I.A). Northern 
also suggested PHMSA define a time period for occupation of an 
identified site which, they contended, would eliminate the need to 
address locations where a gathering of people is truly transient.
    11. TransCanada reported its belief that the current HCA criteria 
provide an appropriate risk focus. In support of this belief, they 
noted that only 3 percent of their US transmission pipeline mileage is 
in HCAs but this includes 45 percent of the population within a 
potential impact radius of their pipelines.
    12. The Iowa Utilities Board opposed changes to the HCA criteria to 
encompass more mileage. IUB commented that such changes would divert 
resources from application to higher-risk pipeline segments and there 
has been no demonstration that non-HCA pipeline segments pose as much 
risk as those currently defined as HCA.
    13. Two private citizens and the Commissioners of Wyoming County, 
Pennsylvania, suggested the existence of one structure intended for 
human occupancy within a potential impact circle should be sufficient 
to define an HCA. These commenters noted that catastrophic consequences 
(i.e., loss of life) are still possible in such sparsely populated 
areas. The Commissioners noted homes in their jurisdiction generally 
did not encroach on the pipelines; the homes were there first and the 
pipeline encroached on what should have been a safe zone around the 
home. They implied pipeline operators should expect a higher burden to 
assure safety in such circumstances.

[[Page 20745]]

    14. The Pipeline Safety Trust commented that there should be a 
single set of criteria defining HCAs and that these criteria should be 
known to the public. They contended the public currently has no 
information on the criteria defining HCAs.
    15. The California Public Utilities Commission commented that HCA 
criteria should be revised to include more pipeline mileage and that 
method 2 (use of potential impact circles) should be eliminated.
    16. The Alaska Natural Gas Development Authority suggested that the 
definition of an HCA should accommodate the phenomenon of rapid growth 
in previously rural areas. They noted that such growth has occurred 
within Alaska due, in part, to disposal of state lands.
    17. NAPSR suggested that PHMSA require all transmission pipelines 
to meet Class 3 and 4 requirements and eliminate HCAs. NAPSR contended 
that focusing resources on higher-risk pipelines is bad public policy, 
since an accident anywhere poses a risk to public safety and reduces 
public confidence.
    18. The Texas Pipeline Association, Texas Oil & Gas Association and 
several pipeline operators objected to the implication in the ANPRM 
that assessment costs have decreased. They contended that costs have 
actually increased due to such factors as operational cost escalation 
and increased costs to address cased pipeline segments.
    19. INGAA and a number of pipeline operators contended that costs 
cannot be estimated accurately absent a specific regulatory proposal. 
They suggested that additional costs would be minimal if expanding HCA 
mileage results in actions similar to INGAA's Integrity Management--
Continuous Improvement (IMCI) action plan, but that costs could be high 
if different requirements are imposed.
    20. INGAA reported that a recent survey showed that its members' 
identified baseline IM assessments will cover 64 percent of members' 
pipeline mileage, only 4 percent of which is in HCAs. INGAA stated that 
these assessments will have covered 90 percent of the population within 
a potential impact radius of the pipelines.
    21. Southwest Gas and Paiute provided cost estimates for conducting 
IM assessments on their pipeline systems: $45,000 per mile for direct 
assessment, up to $125,000 per mile for in-line inspection, and from 
$200,000 to $2 million per instance where changes need to be made to a 
pipeline to accommodate instrumented pigs.
    22. The California Public Utilities Commission and MidAmerican 
commented that costs would increase if the changes suggested in the 
ANPRM were made, but they provided no specific estimates.
    23. APGA noted that costs incurred by or passed on to municipal 
utilities are costs to local governments, since the utilities are, 
themselves, government agencies.
    24. Paiute and Southwest Gas noted that costs to local governments, 
including preparation of permits, paving repairs, etc., can be high.
    25. An anonymous commenter suggested that costs are not likely to 
increase much, since most operators already assess more than HCAs and 
IM has fostered growth in ILI vendors.
    26. Kern River noted that its costs would not increase much, since 
the company is already under similar restrictive requirements via 
special permit.
    27. Accufacts noted that safety is not free. They suggested that 
relative ranking of assessment methods, by cost, is not likely to have 
changed. They cautioned that costs used in cost-benefit analyses 
supporting any rules must be credible and should have an auditable 
trail available to the public. They suggested that serious accidents 
can be a ``cost'' of associated deregulation and lack of proper, 
effective, and efficient safety regulatory oversight for this critical 
infrastructure.
Response to Question A.1 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that the definition of HCAs is adequate, and does not propose to 
modify the definition of scope of HCAs in this proposed rulemaking. 
However, to afford additional protections to other segments along the 
pipeline, PHMSA is proposing to apply selected IM program elements 
(namely assessment and remediation of defects) to areas outside HCAs 
that are newly defined as MCAs. PHMSA believe this approach applies 
appropriate risk-based levels of safety.
    A.2. Should the HCA definition be revised so that all Class 3 and 4 
locations are subject to the IM requirements? What has experience shown 
concerning the HCA mileage identified through present methods (e.g., 
number of HCA miles relative to system mileage or mileage in Class 3 
and 4 locations)? Should the width used for determining class location 
for pipelines over 24 inches in diameter that operate above 1000 psig 
be increased? How many miles of HCA covered segments are Class 1, 2, 3, 
and 4? How many miles of Class 2, 3, and 4 pipe do operators have that 
are not within HCAs?
    A.3. Of the 19,004 miles of pipe that are identified as being 
within an HCA, how many miles are in Class 1 or 2 locations?
    1. Industry trade associations, pipeline operators, and the Iowa 
Utilities Board objected to the suggestion all Class 3 and 4 locations 
should be treated as HCA. They noted class location does not have a 
direct relationship to risk. Small, low-pressure pipelines with no 
structures intended for human occupancy within the PIR (or for which 
the PIR is contained entirely within the right of way) could be Class 3 
or 4 under current definitions. INGAA noted approximately 90 percent of 
Class 3 and 4 mileage not in HCA is presently assessed through over 
testing during IM assessments. Kern River commented that class location 
is an outmoded system that is confusing and unduly complex. Many of 
these commenters noted there is no demonstration of need for including 
all Class 3 and 4 areas, since existing HCA criteria adequately 
identify areas posing higher risks.
    2. Public commenters took a contrary position, suggesting class 
locations are a reasonable basis for increasing HCA mileage. Pipeline 
Safety Trust and California Public Utilities Commission commented all 
Class 3 and 4 locations should be HCA. They noted these are all highly 
populated areas putting more people at risk from pipeline accidents. 
CPUC noted the location of the significant 2010 pipeline accident in 
San Bruno, CA, could have avoided HCA classification if method 2 of the 
current definition had been used. An anonymous commenter supported this 
position, suggesting all Class 3 and 4 locations be treated as HCA and 
use of method 2 be restricted to Class 1 and 2 locations; this 
commenter contended use of method 2 to exclude some portions of Class 3 
and 4 locations from HCA classification is inappropriate. This 
commenter further suggested the definition of Class 4 locations be 
revised, contending that the criterion of 4-story buildings being 
``prevalent'' is not specific enough. Thomas Lael, an industry 
consultant, suggested all Class 4 locations should be HCA. Lael 
contended that this would be an easy change and would assure that the 
highest risk pipe is included.
    3. NAPSR also suggested all Class 3 and 4 locations should be 
classified as HCA. NAPSR noted this is an alternative to their 
preferred solution of eliminating HCA and requiring that all 
transmission pipelines meet Class 3 and 4 requirements.

[[Page 20746]]

    4. One public commenter went further. He suggested a new 
classification, Class 5, be established encompassing all pipeline in 
cities with populations of more than 100,000. He further suggested pipe 
in this new class should meet enhanced construction requirements, 
including required installation of automatic valves to isolate the 
pipeline in the event of an incident. He contended the existing 
regulations impose inadequate safety requirements on urban pipelines.
    5. Accufacts suggested PHMSA focus first on closing loopholes and 
gaps rather than increasing HCA mileage. They commented increasing 
covered mileage without closing gaps would produce only the illusion of 
safety.
    6. Northern Natural Gas suggested PHMSA consider an option of 
eliminating method 2 of the current HCA definition. They contended such 
a change would be easy to accomplish. At the same time, they questioned 
its efficacy, suggesting that it would result in limited or no increase 
in safety while imposing large costs.
    7. INGAA and many pipeline operators objected to the suggested 
increase in the width of a class location unit for larger, high-
pressure pipelines. They noted such a change would contravene the goals 
of IM and divert resources to pipe of lower risk, and pipe of this type 
posing high risks to population concentrations is already included as 
HCA based on its potential impact radius (which could be larger than 
220 yards).
    8. Here, again, public commenters generally took a contrary 
position. Pipeline Safety Trust suggested class location width should 
be at least as much as the potential impact radius. PST noted the PIR 
is intended to focus on areas requiring more protection while the 
existing class location width is arbitrary. Two private citizens 
agreed, one noting that large-diameter, high-pressure gathering 
pipelines in the Marcellus shale area are located slightly more than 
220 yards from pre-existing houses and the other suggesting the class 
location width in higher-class areas should be 220 yards or the PIR, 
whichever is larger. Accufacts would go further, suggesting class 
location width be increased for large-diameter pipe regardless of 
pressure. Accufacts contended diameter is a more significant factor in 
determining the potential extent of post-accident damage than is 
pressure, noting the devastation resulting from the San Bruno accident 
extended to a much greater distance than the PIR. The Texas Pipeline 
Association and Texas Oil & Gas Association commented no change should 
be made until the studies required by the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 are completed.
    9. INGAA and a number of pipeline companies submitted data 
concerning the amount of pipeline mileage currently in HCAs. INGAA's 
data is based on a survey of its members.

----------------------------------------------------------------------------------------------------------------
                          INGAA              Paiute             SWGas           MidAmerican     Northern Natural
----------------------------------------------------------------------------------------------------------------
Class 1...........  475 miles HCA,     1 mile HCA, 632    <1 of 382 miles    0.63 miles HCA,    0.1% of all
                     103,286 not.       not.               are HCA.           493.11 not.        mileage is HCA.
Class 2...........  535 miles HCA,     0 miles HCA, 55    <1 of 20 miles     0.98 miles HCA,    2% of mileage is
                     11,318 not.        not.               are HCA.           101.92 not.        HCA.
Class 3...........  4,100 miles HCA,   26 miles HCA, 142  185 miles HCA,     44.96 miles HCA,   27% of mileage
                     4, 646 not.        not.               242 not.           128.38 not.        is HCA.
Class 4...........  24 miles HCA, 5    None of less than  6 miles HCA, 5     no HCA mileage...  no data
                     not.               1 mile is HCA.     not.                                  reported.
----------------------------------------------------------------------------------------------------------------

    10. Iowa Association of Municipal Utilities reported its members 
have zero HCA miles in any class. Most member transmission pipelines 
are in Class 1 locations. Members have 1.46 miles of Class 2 pipe and 
one mile in Class 3.
    11. Ameren Illinois reported 3.5 of its 82 HCA miles are in Class 1 
or 2.
    12. Kern River reported it has 18.51 HCA miles in Class 1 and 3.14 
miles in Class 2, of a total of 95.96 miles of HCA.
    13. On March 15, 2012, PHMSA received a petition for rulemaking 
from the Jersey City Mayor's office contending that the current Class 
Location system ``does not sufficiently reflect high density urban 
areas, as the regulation fails to contemplate either (1) the dramatic 
differences in population densities between highly congested areas and 
other less dense Class 4 Locations, or (2) the full continuum of 
population densities found in urban areas themselves.'' Based on this, 
Jersey City petitioned PHMSA to add three (3) new Class Locations, 
which would be defined as follows:
     A Class 5 location is any class location unit that 
includes one or more building(s) with between four (4) and eight (8) 
stories;
     A Class 6 location is any class location unit that 
includes one or more building(s) with between nine (9) and forty (40) 
stories;
     A Class 7 location is any class location unit that 
includes at least one building with at least forty-one (41) stories.
Response to Questions A.2 and A.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that HCAs should not be based exclusively on class location. 
Similarly, PHMSA does not propose to define MCAs based on class 
location. PHMSA proposes that moderate consequence area means an 
onshore area that is within a potential impact circle, as defined in 
Sec.  192.903, containing five (5) or more buildings intended for human 
occupancy, an occupied site, or a right-of-way for a designated 
interstate, freeway, expressway, and other principal 4-lane arterial 
roadway as defined in the Federal Highway Administration's Highway 
Functional Classification Concepts, Criteria and Procedures, and does 
not meet the definition of high consequence area, as defined in Sec.  
192.903. This assures a comparable level of safety for all pipelines, 
regardless of class location. As a result, PHMSA is not proposing to 
expand class locations in this proposed rule. The issue of expanding 
class locations is addressed in the class location report which is 
available for review in the docket while formulating comments.
    A.4. Do existing criteria capture any HCAs that, based on risk, do 
not provide a substantial benefit for inclusion as an HCA? If so, what 
are those criteria? Should PHMSA amend the existing criteria in any way 
which could better focus the identification of an HCA based on risk 
while minimizing costs? If so, how? Would it be more beneficial to 
include more miles of pipeline under existing HCA IM procedures, or, to 
focus more intense safety measures on the highest risk, highest 
consequence areas or something else? If so why?
    1. INGAA and several pipeline operators commented the method 
described in paragraph 2 in the

[[Page 20747]]

definition of HCA in Sec.  192.903 appropriately focuses attention on 
at-risk populations. They contended that the method described in 
paragraph 1 in the definition of HCA in Sec.  192.903 captures some 
inappropriate areas.
    2. Texas Pipeline Association, Texas Oil & Gas Association, and 
Ameren Illinois contended the existing criteria do not capture areas 
not posing risk. They noted the criteria were based on the science of 
pipeline accidents to identify high-risk areas.
    3. Paiute and Southwest Gas commented neither more HCA miles nor 
additional safety measures are needed. They contended existing criteria 
are adequate and rule provisions for preventive and mitigative measures 
and to consider pipe with similar conditions when anomalies are found 
in HCA are sufficient to address non-HCA pipeline segments.
    4. APGA recommended the regulations be modified to treat 
transmission pipelines operated by local distribution companies, most 
of which operate at less than 30 percent SMYS, under distribution 
integrity management rather than transmission IM. APGA suggested this 
is an optimum time to make this change, which was discussed in the 
phase 1 work leading up to the distribution IM rule. Atmos agreed, 
noting failure by leakage rather than rupture, similar to distribution 
pipelines, is much more prevalent for this low-stress pipeline and it 
thus poses much lower risks.
    5. Northern Natural Gas suggested PHMSA revisit its treatment of 
``well defined areas'' that constitute identified sites. They contended 
current practice treats an entire area as an identified site even if 
only an unoccupied corner is within the PIR and persons congregating 
are outside that critical radius.
    6. MidAmerican suggested PHMSA consider adding a multiplier to the 
PIR equation for higher-stress pipelines. They contended this could 
capture more high-risk pipe without adversely affecting low-stress 
pipelines that pose considerably less risk.
    7. Atmos commented no change should be made which would increase 
the amount of HCA mileage, contending that this would dilute the 
current focus on high-risk pipe.
    8. INGAA and several of its members suggested PHMSA rely on its 
Integrity Management--Continuous Improvement (IMCI) initiative to 
address pipeline in non-HCA areas.
Response to Question A.4 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that the existing method for identifying HCAs and calculating 
PIR is appropriate and is not proposing a change to either. However, 
PHMSA disagrees that existing requirements are sufficient for non-HCAs 
segments. PHMSA believes non-HCA segments where people congregate 
should be afforded additional protections. Therefore, PHMSA is 
proposing that selected IM program elements (assessment and remediation 
of defects) be applied to MCAs.
    A.5. In determining whether areas surrounding pipeline right-of-
ways meet the HCA criteria as set forth in part 192, is the potential 
impact radius sufficient to protect the public in the event of a gas 
pipeline leak or rupture? Are there ways that PHMSA can improve the 
process of right-of-ways HCA criteria determinations?
    1. INGAA, AGA, GPTC and a number of pipeline operators contended 
the existing PIR criteria are sufficiently conservative. They noted the 
criteria were derived from scientific analysis of the consequences of 
past pipeline accidents. Texas Pipeline Association and Texas Oil & Gas 
Association commented there is no reason to modify the PIR criteria or 
to establish alternate criteria to define HCAs; they contended there is 
no evidence the current PIR definition has provided insufficient 
protection to the public.
    2. One private citizen and Alaska's Department of Natural Resources 
suggested HCA criteria should be revised to consider parallel pipelines 
in a common right of way, contending that an accident on one pipeline 
could impact adjacent lines, thus compounding consequences. They 
further suggested requirements for pipelines in common rights of way 
should include minimum spacing between the pipelines.
    3. An anonymous commenter suggested plume releases be considered to 
determine which pipeline segments can affect an HCA, contending that 
this would be a good practice.
    4. AGA, Texas Pipeline Association, Texas Oil & Gas Association, 
GPTC, and several pipeline operators cautioned against use of the term 
``right of way'' in the context of defining HCAs. They noted this term 
is imprecise and the actual location of the pipeline, rather than an 
ill-defined right of way, is the important factor in evaluating risk.
    5. Accufacts, INGAA, and numerous pipeline operators cautioned 
against discussions that imply that the PIR concept is applicable to 
considerations of risk from pipeline leaks. These commenters noted that 
the PIR is based on the consequences of a pipeline rupture and 
resulting conflagrations and was never intended to address leaks not 
involving fires.
    6. ITT Exelis Geospatial Systems, a company providing services to 
the pipeline industry, noted accurate location of a pipeline is as 
important to assuring adequate protection of high-risk populations as 
is the calculation of PIR.
    7. Accufacts suggested PHMSA require a report of the actual impact 
area, including aerial photographs, within 24 hours of any pipeline 
rupture. Accufacts contended this data would provide a further basis 
for continuing review of PIR adequacy.
Response to Question A.5 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that the existing definition of PIR is appropriate at this time. 
PHMSA believes that adjusting the PIR formula based on parallel 
pipelines in the right-of-way, or other right-of-way factors, are 
premature at this time. Also, PHMSA acknowledges that the PIR approach 
only applies such incidents resulting in explosions and fires. While 
certain gases might be better modeled using plume models, such models 
have not been carefully studied or developed. However, PHMSA plans to 
pursue (outside the scope of this rulemaking) additional incident 
reporting requirements for the purpose of further evaluating the extent 
of damage following incidents.
    A.6. Some pipelines are located in right-of-ways also used, or 
paralleling those, for electric transmission lines serving sizable 
communities. Should HCA criteria be revised to capture such critical 
infrastructure that is potentially at risk from a pipeline incident?
    1. INGAA, AGA, Texas Pipeline Association, Texas Oil & Gas 
Association, and many pipeline operators objected to any potential 
inclusion of ``critical infrastructure'' in HCA criteria. They noted 
there is no history of problems caused by impacts on infrastructure, 
there is little public risk involved, data regarding such 
infrastructure would be difficult for pipeline operators to obtain, and 
issues involving potential interactions with critical infrastructure 
are usually addressed during pipeline planning and construction.
    2. GPTC and Nicor recommended HCA criteria not be revised to 
include critical infrastructure. They noted the intent of defining HCAs 
is to address risk to life and not property damage and damages to local 
infrastructure are unlikely to result in consequences similar to those 
that could affect population concentrations near the

[[Page 20748]]

pipeline. Atmos agreed, noting planning for accident-caused outages is 
a responsibility of electric system operators.
    3. Pipeline Safety Trust, Accufacts, NAPSR, Alaska Department of 
Natural Resources, California Public Utilities Commission and ITT 
Exelis Geospatial Systems recommended critical infrastructure be 
included among HCA-defining criteria. Several of these commenters 
suggested infrastructure beyond electric transmission be considered, 
including, for example, water and sewage treatment plants, fire 
stations, and communications facilities. The commenters noted damages 
to critical infrastructure can lead to cascading effects and additional 
public safety consequences. ITT Exelis acknowledged these 
considerations may be secondary to loss of life but contended they are 
still important to public safety.
    4. Northern Natural Gas, Kern River, MidAmerican, Paiute, and 
Southwest Gas noted determining the impact of damages to infrastructure 
items is complex. These commenters suggested it is not practical to 
define what constitutes ``critical'' infrastructure, from a public 
safety standpoint, on a generic basis. They recommended PHMSA leave 
consequence determination to operators, as part of their risk 
assessments, providing additional guidance for such considerations if 
needed.
    5. An anonymous commenter suggested more frequent tests of cathodic 
protection and coating surveys be required in areas potentially subject 
to induced currents from nearby electric transmission infrastructure.
Response to Question A.6 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that there have been relatively few pipeline incidents that have 
had a major impact on critical infrastructure. PHMSA also acknowledges 
that the PIR formula was developed based on life safety (i.e., heat 
flux that result in fatalities). However, PHMSA is also aware of recent 
incidents that, among other consequences, damaged and caused temporary 
closure of interstate highways. Among them are the 2012 incident at 
Sissonville, WV and the 2010 incident at New Delhi, LA, which also 
resulted in one fatality. Even though PHMSA is not proposing to revise 
the HCA criteria or the PIR formula, PHMSA is proposing to include 
major highways in the MCA criteria.
    A.7. What, if any, input and/or oversight should the general public 
and/or local communities provide in the identification of HCAs? If 
commenters believe that the public or local communities should provide 
input and/or oversight, how should PHMSA gather information and 
interface with these entities? If commenters believe that the public or 
local communities should provide input and/or oversight, what type of 
information should be provided and should it be voluntary to do so? If 
commenters believe that the public or local communities should provide 
input, what would be the burden entailed in providing provide this 
information? Should state and local governments be involved in the HCA 
identification and oversight process? If commenters believe that state 
and local governments be involved in the HCA identification and 
oversight process what would the nature of this involvement be?
    1. INGAA and its pipeline operator members commented no additional 
public involvement is needed. INGAA noted consultation is required 
under the current regulations, and it seldom identifies any relevant 
information. Additional involvement, INGAA contends, would likely lead 
to inconsistencies and would degrade the technical/scientific basis for 
determining HCAs.
    2. AGA and several of its member companies suggested local 
government agencies should provide information when requested by 
pipeline operators. They contended additional required involvement 
would pose an additional burden on pipeline operators while adding no 
benefit. AGA noted information from its members suggests that local 
government agencies very rarely point out identified sites not 
otherwise known to the pipeline operator.
    3. Texas Pipeline Association, Texas Oil & Gas Association, GPTC, 
Nicor, Ameren Illinois and Oleksa and Associates (a pipeline industry 
consultant) suggested further involvement of local governments not be 
required. These commenters contended pipeline operators have more 
relevant knowledge and involvement of inexperienced entities in 
identifying HCAs is more likely to result in confusion than useful 
information. The Texas associations suggested current public awareness 
requirements afford sufficient involvement of local agencies.
    4. Accufacts noted local governmental agencies have maps 
identifying locations important to public safety and suggested these 
maps should be used by pipeline operators in HCA determinations. 
Accufacts believes this could assist operators in assuring 
consideration of accurate, complete, and current information.
    5. Northern Natural Gas reported it has a phone number and email 
address that local residents and agencies can use to provide input to 
its HCA determinations. Northern further reported no HCAs have been 
identified from information provided via these avenues that were not 
otherwise known to the company.
    6. Public commenters suggested local residents and government 
agencies should receive more information concerning pipelines and HCAs. 
One commenter suggested operators should provide copies of IM plans 
upon request, and should provide prior notification to residents within 
a PIR of assessments and a subsequent report of assessment results or 
problems otherwise identified. This individual also suggested locations 
of HCAs and assessment trend results should be provided to local 
communities upon request. The League of Women Voters of Pennsylvania 
suggested distribution integrity management plans should be readily 
available and the public should be involved in decisions related to 
those plans.
    7. Pipeline Safety Trust commented public review should be part of 
any process by which PHMSA reviews or approves of HCA identifications.
    8. Wyoming County Pennsylvania Commissioners suggested stakeholder 
meetings and public comment periods be required as part of HCA 
identification. They noted local residents know their communities 
better than others, including expected changes that could affect HCA 
identification.
    9. AGA and several of its member operators recommended local 
governments play no role in oversight of HCA determinations. They 
contended this would increase burden and result in inconsistencies and 
confusion.
    10. An anonymous commenter suggested existing public awareness 
contacts should be used to improve HCA determinations. The commenter 
expressed the belief this existing structure could allow low-cost 
involvement of local officials in such determinations.
    11. The NTSB suggested PHMSA work with states to employ oversight 
of pipeline IM plans based on objective metrics. The NTSB noted this 
would be consistent with recommendation P-11-20 resulting from its 
investigation of the San Bruno, CA pipeline accident.
    12. Iowa Association of Municipal Utilities noted local government 
employees are involved when HCA determinations are made by municipal 
utilities and further requirements for

[[Page 20749]]

local involvement would be inappropriate for such operators.
Response to Question A.7 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
is continuing to evaluate this aspect of integrity management but has 
not yet reached any conclusions. PHMSA may consider this input for 
future action, if applicable.
    A.8. Should PHMSA develop additional safety measures, including 
those similar to IM, for areas outside of HCAs? If so, what would they 
be? If so, what should the assessment schedule for non-HCAs be?
    1. Pipeline operators and their associations generally agreed 
additional measures were not needed outside HCA. INGAA and several 
transmission pipeline operators suggested operators be allowed to apply 
the principles of ASME/ANSI B31.8S voluntarily, as needed. INGAA noted 
this is the concept behind its Integrity Management--Continuous 
Improvement (IMCI) initiative.
    2. AGA and a number of its member operators noted the regulations 
already require implementation of preventive and mitigative measures 
outside of HCA for low-stress pipe (Sec.  192.935(d)). These 
requirements include using qualified personnel to conduct work that 
could adversely affect the integrity of the covered segment, collecting 
excavation damage information, and participating in one-call systems.
    3. Ameren Illinois and MidAmerican commented additional measures 
are not needed, because existing operations & maintenance requirements 
already assure integrity.
    4. GPTC and Nicor agreed, noting it would be inappropriate to apply 
IM measures outside of HCA and existing requirements are assuring an 
adequate level of safety.
    5. Atmos contended the existing provision requiring that operators 
evaluate and remediate non-HCA pipeline segments when corrosion is 
found during an IM assessment of a covered pipeline segment (Sec.  
192.917(e)(5)) already provides that actions be taken to assure the 
integrity of non-HCA pipeline segments.
    6. Texas Pipeline Association and Texas Oil & Gas Association would 
not object to a phased expansion of IM requirements provided that 
required assessment intervals are scientifically based. The 
associations noted Texas pipelines are already subject to the broader 
requirements of the Texas IM rule. They commented phased implementation 
would assure the next-highest risks are addressed first and would allow 
time for IM-support resources to grow.
    7. Iowa Association of Municipal Utilities commented new 
requirements are not needed for its members' pipelines. These lines are 
small-diameter, low-pressure, odorized, and already pose low risk.
    8. Northern Natural Gas suggested PHMSA expand the HCA definition 
gradually over time rather than imposing IM requirements outside HCA. 
Northern commented such an approach would retain and expand the focus 
on areas posing the highest risk.
    9. Accufacts commented repair criteria, including required response 
times, and reporting of anomalies should be the same in- or outside 
HCA, since the progression of an anomaly to failure is unrelated to 
whether the anomaly exists within or outside of an HCA.
    10. Pipeline Safety Trust suggested non-HCA pipeline segments 
should be subject to a baseline of IM requirements.
    11. The Commissioners of Wyoming County Pennsylvania suggested 
PHMSA consolidate operators' best practices and require assessment of 
all pipe frequently enough to realize a benefit. They commented this 
approach would assure a consistent level of public protection 
regardless of the practices of individual pipeline operators.
    12. California Public Utilities Commission noted this question 
would be moot if method 2 for defining HCA is eliminated.
Response to Question A.8 Comments
    PHMSA appreciates the information provided by the commenters. 
Although most industry commenters did not support expansion of 
integrity management requirements outside HCAs, PHMSA believes 
additional protections are needed for pipeline segments where people 
are expected within the PIR. In this NPRM, PHMSA proposes an approach 
that balances the need to provide additional protections for persons 
within the potential impact radius (PIR) of a pipeline rupture (outside 
of a defined HCA), and the need to prudently apply IM resources in a 
fashion that continues to emphasize the risk priority of HCAs. The 
proposed regulation would require selected aspects of IM programs 
(namely, integrity assessments and repair criteria) to be applicable 
for selected non-HCA segments defined as MCAs. An MCA would be a 
segment located where persons live and work and could reasonably be 
expected to be located within a pipeline PIR. PHMSA would propose 
requirements that integrity assessments be conducted, and that 
injurious anomalies and defects be repaired in a timely manner, using 
similar standards in place for HCAs. However, the other program 
elements of a full IM program contained in 49 CFR part 192, subpart O 
would not be required for MCA segments.
    A.9. Should operators be required to submit to PHMSA geospatial 
information related to the identification of HCAs?
    1. Most industry commenters, including INGAA, AGA, and numerous 
pipeline operators supported this proposed requirement. They noted 
submission of this data will be required for PHMSA to comply with the 
mapping provisions of the Pipeline Safety, Regulatory Certainty, and 
Job Creation Act of 2011.
    2. Accufacts, Alaska Department of Natural Resources, California 
Public Utility Commission, and one private citizen agreed, suggesting 
PHMSA should know where HCAs are located and that this information is 
important to emergency responders. CPUC also suggested operators should 
be required to submit this information to State regulatory authorities 
as well.
    3. Pipeline Safety Trust also supported this proposal, adding the 
information should be shared with the public.
    4. League of Women Voters of Pennsylvania and Accufacts also 
supported making maps identifying pipeline locations, including HCA, 
available to the public.
    5. Atmos, Northern Natural Gas, Kern River, Nicor, and GPTC opposed 
a requirement to submit this information. They noted this is a large 
amount of information which is available for audits and questioned how 
it would be used by PHMSA and how related security issues would be 
addressed.
    6. Ameren Illinois suggested a requirement to submit HCA locations 
is not needed, since location data on the entire pipeline system must 
already be submitted to the National Pipeline Mapping System.
    7. Texas Pipeline Association, Texas Oil & Gas Association, and 
MidAmerican agreed that providing HCA information as part of NPMS 
submissions is adequate. They noted this is consistent with Section 6 
of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 
2011.
Response to Question A.9 Comments
    PHMSA appreciates the information provided by the commenters. Most 
commenters supported the submittal of HCA information in geospatial 
format. As noted by one commenter, this is required by the Act. 
Although outside

[[Page 20750]]

the scope of this rulemaking, PHMSA is pursuing data reporting 
improvements by proposing revisions to its currently approved 
information collection for the National Pipeline Mapping System. PHMSA 
has published several Federal Register notices and held several public 
workshops on the proposals.
    A.10. Why has the number of HCA miles declined over the years?
    1. Responses to this question consisted of speculation regarding 
reasons why the number of HCA miles may have declined. No commenters 
reported having specific data to describe the reducing trend.
    2. AGA suggested pipe replacement, reductions in MAOP, and use of 
better data could be among the many reasons for a decline in HCA 
mileage.
    3. INGAA speculated the reduction could be a result of operators 
changing from method 1 to method 2 to identify HCAs and abandoning or 
retiring older pipelines.
    4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, 
and a private citizen agreed a change in the method for identifying 
HCAs is a likely reason for the decreasing mileage trend.
    5. Northern Natural Gas commented changes in land use over time 
result in changes in the pipeline segments identified as HCA. Northern 
noted it has changed from method 1 to method 2 for identifying HCA but 
that the change had resulted in an increase in HCA mileage rather than 
a decrease. Kern River also reported that its HCA mileage is 
increasing, citing changes in land use along the pipeline as the reason 
for this change.
    6. GPTC and Nicor suggested operational changes and removal of pipe 
from service could be the cause of the observed changes.
    7. Iowa Utilities Board noted reductions in pressure and other 
operational changes can eliminate covered pipeline segments. IUB also 
suggested a change from method 1 to method 2 and better analyses of 
potential impact circles, etc. could have resulted in decreased HCA 
mileage.
    8. MidAmerican noted its HCA mileage has fluctuated but remains 
relatively constant overall. They noted periodic fluctuations result 
from changes in various parameters that go into identifying HCAs.
    9. A private citizen suggested operators may be buying properties 
within potential impact circles and razing them or that new pipelines 
in rural areas may be replacing current pipelines.
    10. An anonymous commenter suggested HCA mileage is decreasing 
because operators are getting better at identifying HCAs. The commenter 
noted operators have been doing so for 9 years.
Response to Question A.10 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
considered this input in its evaluation mandated by the Act.
    A.11. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible.
    1. Accufacts commented property damage costs reported to PHMSA 
following pipeline incidents appear to be understated. Accufacts noted 
this raises serious questions about the validity of cost-benefit 
analyses performed using this data.
    2. Iowa Association of Municipal Utilities commented the costs to 
comply with IM-like requirements are not justified for small, low-
pressure transmission pipelines such as those operated by its members. 
Significant costs to develop IM plans, evaluate remote valves, and 
comply with other IM requirements must be passed on to a small rate 
base for many municipal utilities.
    3. ITT Exelis Geospatial Systems suggested HCA criteria be revised 
and requirements for protection of critical infrastructure and 
populated areas be made more prescriptive. They commented such changes 
would require that leak surveys be performed more frequently, providing 
improved safety.
    4. ITT Exelis Geospatial Systems reported its leak detection 
systems, developed as part of research jointly sponsored with DOT and 
other agencies, could facilitate this testing and initial costs would 
be offset by longer term savings.
    5. California Public Utilities Commission observed the public has 
indicated its desire for more prescriptive safety requirements.
Response to Question A.11 Comments
    The Act requires that the Secretary of Transportation to evaluate 
whether integrity management requirements should be expanded beyond 
HCAs and whether such expansion would mitigate the need for class 
location requirements. The proposed rulemaking does not change the HCA 
definition. However, PHMSA is proposing pipeline assessment 
requirements in new Sec.  192.710 for newly defined moderate 
consequence areas (MCAs). PHMSA is also proposing new requirements in 
Sec.  192.607 for verification of pipeline material and Sec.  192.624 
for MAOP verification would also apply to MCAs. PHMSA performed a 
Preliminary Regulatory Impact Analysis, using the best available data 
and information. It is available on the docket and PHMSA invites 
comments on the PRIA.

B. Strengthening Requirements To Implement Preventive and Mitigative 
Measures for Pipeline Segments in HCAs

    Section 192.935 requires gas transmission pipeline operators to 
take additional measures, beyond those already required by part 192, to 
prevent a pipeline failure and to mitigate the consequences of a 
potential failure in a HCA following the completion of a risk 
assessment. Section 192.935(a) specifies examples of additional 
measures, which include, but are not limited to installing automatic 
Shut-off Valves or Remote Control Valves; installing computerized 
monitoring and leak detection systems; replacing pipe segments with 
pipe of heavier wall thickness; providing additional training to 
personnel on response procedures; conducting drills with local 
emergency responders; and implementing additional inspection and 
maintenance programs. In the ANPRM, PHMSA expressed concern that these 
additional measures are not explicitly required. As a result, operators 
may not be employing the appropriate additional measures as intended. 
Section 192.935(b) specifies that operators are also required to 
enhance their damage prevention programs and to take additional 
measures to protect HCA segments subject to the threat of outside force 
damage (non-excavation). PHMSA also noted in the ANPRM that the 
provisions in Sec.  192.935 only apply to HCAs and that the expansion 
of the HCA definition would increase the mileage of pipelines subject 
to Sec.  192.935. Further, PHMSA acknowledged the consideration of 
expanding preventive and mitigative measures to pipelines outside of 
HCAs. The following are general comments received related to the topic 
as well as comments related to the specific questions:
General Comments for Topic B
    1. INGAA suggested PHMSA can substantially improve prevention and 
mitigation of accidents caused by excavation damage by facilitating 
full implementation of state damage prevention programs. INGAA further 
suggested PHMSA actively promote the use of 811 one-call programs. 
INGAA noted excavation damage remains the most prevalent cause of 
serious incidents and failure to notify is a primary cause of these 
incidents. Many pipeline operators supported the INGAA comments.

[[Page 20751]]

    2. INGAA, supported by many of its pipeline operator members, noted 
it has a policy goal to apply integrity management principles, 
voluntarily, to pipelines beyond HCAs. Their goal is to address 90 
percent of the population near pipelines by 2020 and 100 percent by 
2030 through application of appropriate principles from ASME/ANSI 
B31.8S.
    3. AGA supported application of IM principles, but not assessment 
requirements, outside HCAs. AGA commented requiring operators to 
understand and address risks is a good application of IM principles. 
Many pipeline operators supported the AGA comments.
    4. AGA commented the ANPRM incorrectly states that Sec.  192.935 
applies only to pipe within HCAs. AGA noted paragraph (d) of that 
section applies to low-stress pipe in Class 3 and 4 areas that is not 
in HCAs.
    5. California Public Utilities Commission suggested pipelines 
installed prior to the promulgation of federal pipeline safety 
requirements (so-called ``pre-code'' pipe) be reassessed more 
frequently.
    6. Alaska Natural Gas Development Authority commented Alaska's 
experience indicates improved pipeline design and construction 
requirements are needed to assure pipeline integrity. These would 
include stronger pipe, improved requirements for mainline valves 
(including spacing and remote operation), and improved corrosion 
control. The Authority also commented that design requirements need to 
accommodate likely changes in class location, noting that explosive 
growth in some Alaska areas has resulted in rapid changes from Class 1 
to Class 3.
    7. One private citizen suggested some level of assessment should be 
required for all pipelines.
    8. Another private citizen suggested integrity management plans for 
densely populated areas (Class 4 and Class 5--a new class suggested by 
the commenter encompassing cities with population greater than 100,000) 
should be developed in consultation with local emergency responders. 
The commenter further suggested these plans should be available at the 
FERC environmental impact study stage and should be reviewed with local 
authorities.
    9. Another private citizen suggested information should be shared 
across pipeline operators, noting this would augment the knowledge of 
individual companies and improve safety. Similarly, the commenter 
suggested PHMSA require operators to submit a list of preventive and 
mitigative measures that have been implemented and reports of their 
effectiveness. The commenter noted PHMSA should know this information 
but apparently does not, as indicated by questions posed in this ANPRM 
(particularly questions B.1 and B.2).
Comments Submitted for Questions in Topic B
    B.1. What practices do gas transmission pipeline operators now use 
to make decisions as to whether/which additional preventive and 
mitigative measures are to be implemented? Are these decisions guided 
by any industry or consensus standards? If so, what are those industry 
or consensus standards?
    1. Most industry commenters indicated ASME/ANSI B31.8S is a common 
standard used to guide decisions concerning preventive and mitigative 
measures. INGAA suggested enhancing this standard would be the best 
approach to provide additional guidance for selection and 
implementation of these measures. Other commenters also cited the GPTC 
Guide as a useful guideline. INGAA listed other standards used by 
pipeline operators, including:

 Common Ground Alliance Best Practices
 Pipelines and Informed Planning Alliance Recommended Practices
 API-RP 1162--Public Awareness Programs,
 API-RP 1166--Excavation Monitoring
 NACE SP0169, other associated NACE standards
 Gas Piping Technology Committee guidance materials
 RSTRENG--A Modified Criterion for Evaluating the Remaining 
Strength of Corroded Pipe
 INGAA Foundation Guidelines for Evaluation and Mitigation of 
Expanded Pipes

    AGA also noted that operators are guided by their own risk 
assessments. Many pipeline operators supported the INGAA and AGA 
comments.
    2. Northern Natural Gas reported it does not rely on a specific 
consensus standard to select preventive and mitigative measures. It 
relies, instead, on company subject matter experts guided by 
statistical analyses of their risk model.
    3. Paiute and Southwest Gas reported they use an algorithm 
combining risk scores, threats, and the value of specific measures. 
Company engineers analyze the results of applying this algorithm and 
develop preventive and mitigative measure implementation plans.
    4. An anonymous commenter noted many pipeline operators are 
implementing actions that could be considered preventive and mitigative 
measures but these actions may not be identified as such if they are 
implemented as part of operations and maintenance activities and not 
specifically included in IM plans.
    5. INGAA suggested PHMSA would benefit by applying ASME/ANSI B31.8S 
in its IM enforcement activities.
    B.2. Have any additional preventive and mitigative measures been 
voluntarily implemented in response to the requirements of Sec.  
192.935? How prevalent are they? Do pipeline operators typically 
implement specific measures across all HCAs in their pipeline system, 
or do they target measures at individual HCAs? How many miles of HCA 
are afforded additional protection by each of the measures that have 
been implemented? To what extent do pipeline operators implement 
selected measures to protect additional pipeline mileage not in HCAs?
    1. INGAA reported many pipeline operators have implemented 
additional preventive and mitigative measures. INGAA does not keep data 
on this and did not provide examples. Some pipeline operators submitted 
examples in support of the INGAA comments. Preventive and mitigative 
measures cited in these examples include:
     Additional reconnaissance (after seismic events, floods, 
etc.);
     Concrete mats over pipelines in areas particularly 
susceptible to excavation damage;
     Encroachment sensors;
     Remotely operated valves;
     Removal of casings;
     Completion of CIS surveys;
     Clearing of rights-of-way;
     Derating/deactivating of pipelines;
     Relocation of pipelines;
     Increased inspection of river crossings;
     Lowering of shallow pipelines;
     Installation of additional marker posts;
     Revising marking standards for locates;
     Completing depth-of-cover surveys;
     Enhancing right-of-way patrols.
    In addition, one pipeline operator reported augmented 
implementation of many requirements of part 192 and implementation of 
some requirements (e.g., operator qualification) beyond their specified 
bounds.
    2. AGA also reported many additional preventive and mitigative 
actions have been implemented but, again, does not keep data on them. 
Examples cited by AGA and its operator members included increased use 
of indirect inspection tools, increased patrols, and investigation of 
apparent instances of encroachment.

[[Page 20752]]

    3. GPTC reported data is not collected concerning voluntary 
measures.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
similarly reported that they do not collect this data, and there was 
only limited response to a survey of their operators regarding this 
question. The associations reported their understanding that measures 
are not generally implemented system-wide.
    5. California Public Utilities Commission reported some CA 
operators are stationing personnel at the location of excavations near 
transmission pipelines. CAPUC also noted California's one-call law 
requires a mandatory field meeting before any excavation near a 
transmission pipeline operating above 60 psi.
    6. An anonymous commenter suggested operators avoid implementing 
non-required actions for fear they will lead to new requirements.
    7. Industry comments indicated data is not collected concerning the 
extent of implementation of voluntary preventive and mitigative 
measures. Some measures are implemented in specific HCAs while others 
may be implemented more broadly across a pipeline system. The extent 
depends largely on the threat being addressed and its prevalence.
    8. Northern Natural Gas reported it has implemented voluntary 
measures outside HCA, citing as examples high-visibility markers in 
Class 1 areas and use of LIDAR leak detection. Northern reported broad 
implementation of voluntary measures is more prevalent than site 
specific use.
    9. MidAmerican reported virtually all of its transmission pipeline 
mileage is subject to at least one preventive and mitigative measure.
    10. Paiute reported nine measures are applied to all of its 856 
miles of transmission pipeline while 13 are applicable to all 27 miles 
of HCA.
    11. Similarly, Southwest Gas has implemented nine measures on 841 
miles and 13 on all 191 miles of HCA.
    12. AGA reported that approximately 195,000 non-HCA miles have been 
assessed, generally through assessing pipe upstream and downstream of 
the HCA segment.
    B.3. Are any additional prescriptive requirements needed to improve 
selection and implementation decisions? If so, what are they and why?
    1. Industry commenters unanimously agreed no new prescriptive 
requirements are needed. INGAA pointed out selection of preventive and 
mitigative measures is based on criteria in consensus standards and 
operator judgment. INGAA contended this allows appropriate 
customization and results in improved safety. AGA agreed, noting 
operators are in the best position to decide what is needed for their 
pipeline systems. GPTC stated that its Guide is sufficient, and there 
has been no demonstrated safety need for additional requirements. 
Several pipeline operators suggested conducting assessments and making 
repairs provides the most effective safety improvement.
    2. Paiute and Southwest Gas suggested a best practices workshop to 
share industry experience could be beneficial.
    3. Accufacts suggested additional prescriptiveness is needed to 
guide decisions regarding remote and automatically operated valves in 
HCA.
    4. The Alaska Department of Natural Resources would suggest signoff 
by a professional engineer on preventive and mitigative action 
decisions.
    5. The NTSB recommended improved use of metrics in inspection 
protocols, citing their recommendations P-11-18 and 19.
    6. One private citizen suggested the lack of specifically-required 
actions in the regulations represents a deficiency in the pipeline 
safety regulatory program. The commenter suggested the extent of 
operator judgment be limited and that state and local officials should 
participate in developing a list of applicable preventive and 
mitigative actions.
    7. An anonymous commenter suggested including more examples of 
preventive and mitigative actions in the regulations would help guide 
operator consideration of appropriate actions. The commenter also 
suggested operators be required to update their risk analyses, and 
selection of preventive and mitigative actions, more frequently 
including after changes in their pipeline systems or the occurrence of 
significant events.
    B.4. What measures, if any, should operators be required explicitly 
to implement? Should they apply to all HCAs, or is there some 
reasonable basis for tailoring explicit mandates to particular HCAs? 
Should additional preventative and mitigative measures include any or 
all of the following: Additional line markers (line-of-sight); depth of 
cover surveys; close interval surveys for cathodic protection (CP) 
verification; coating surveys and recoating to help maintain CP current 
to pipe; additional right-of-way patrols; shorter ILI run intervals; 
additional gas quality monitoring, sampling, and inline inspection tool 
runs; and improved standards for marking pipelines for operator 
construction and maintenance and one-calls? If so, why?
    1. INGAA, supported by many of its pipeline operator members, 
commented prescriptive requirements are not needed. INGAA contended 
prescriptive requirements are neither effective nor efficient and that 
ASME/ANSI B31.8S and the GPTC Guide provide sufficient guidance.
    2. AGA commented one-call requirements and the actions required by 
the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 
are the only actions that should be required on a system-wide basis. 
AGA further suggested it could be appropriate to apply the additional 
measures required of low-pressure pipelines in Sec.  192.935(d) to 
pipelines operating above 30 percent SMYS.
    3. Texas Pipeline Association and Texas Oil & Gas Association 
recommended no new requirements be adopted applying specific preventive 
and mitigative actions throughout pipeline systems. The associations 
noted part 192 already requires application of some measures throughout 
pipeline systems and expressed their conclusion these already-specified 
measures are sufficient.
    4. MidAmerican commented requiring application of specified 
measures throughout pipeline systems would provide a disincentive for 
the application of other measures which could be more appropriate.
    5. The NTSB recommended requirements for leak detection in SCADA 
systems should be improved, citing their recommendation P-11-10.
    6. California Public Utilities Commission recommended operators be 
required to station stand-by personnel at excavations near transmission 
pipelines and operator procedures should specify the actions these 
stand-by personnel must take. CPUC further suggested these standby 
activities should be a covered task under operators' personnel 
qualification programs.
    7. Pipeline Safety Trust recommended PHMSA mandate the NTSB 
recommendations, noting many are similar to the specific measures 
suggested in this question. PST further commented operators should not 
be allowed sufficient latitude to render a regulation meaningless.
    8. An anonymous commenter suggested the regulations should not 
specify particular preventive and mitigative measures but should 
emphasize consideration of potential accident consequences when 
selecting actions. The commenter noted there are too many variables to 
specify particular actions in regulation.

[[Page 20753]]

    9. A private citizen suggested operators should be required to 
conduct drills with local responders periodically as part of their 
integrity management programs. The commenter noted such drills would 
improve coordination and would validate the ability to respond in the 
event of an emergency.
    10. A private citizen suggested stronger enforcement is needed 
based on the belief that operators should already be taking many of the 
actions suggested in this question.
    11. With respect to the specific actions suggested in this 
question:
    a. Line-of-sight markers: National Utility Locating Contractors 
Association recommended line-of-sight markers be required, noting that 
they would reduce the instances of excavators failing to call for a 
locate, which the Common Ground Alliance's Damage Information Reporting 
Tool (DIRT) continues to indicate is a major cause of excavation 
damage. The Association further recommended the message on markers 
should be visible from all angles, noting that most current markers are 
only visible from two directions. The Commissioners of Wyoming County 
Pennsylvania, and MidAmerican suggested line-of-sight markers should be 
required, noting that they are a low-cost good practice for improving 
safety. An industry consultant disagreed, noting installation would be 
impractical in many areas where the sight line is obscured by crops, 
terrain, etc.
    b. Depth of cover: MidAmerican opposed required depth of cover 
surveys, commenting they are not a good indicator of likely damage and 
such surveys are inherently inaccurate. Texas Pipeline Association and 
Texas Oil & Gas Association suggested compliance with depth of cover 
requirements over time is impractical. They noted operators do not have 
full control over rights of way and that owners can make changes. For 
example, a landowner may pave an area following grading which reduces 
the depth of cover. California Public Utilities Commission recommended 
depth of cover surveys be required wherever external corrosion direct 
assessment is applied and where vehicles or other loads capable of 
damaging the pipeline have access to the surface over the pipeline. 
Wyoming County Pennsylvania's Commissioners suggested depth of cover 
surveys be required as a good safety practice.
    c. Close interval surveys: MidAmerican recommended against 
requiring these surveys. The company noted they are only one means of 
determining the adequacy of cathodic protection. The Commissioners of 
Wyoming County Pennsylvania recommended such surveys be required as a 
good safety practice.
    d. Coating surveys and re-coating: MidAmerican opposed a 
requirement for coating surveys, noting holidays are found and repaired 
through in-line inspection and external direct assessment. The company 
further noted pipe replacement is often a superior repair to recoating. 
The Wyoming County Commissioner commented periodic coating surveys are 
a good practice and recommended that they be required.
    e. Additional right of way patrols: MidAmerican and the Wyoming 
County Commissioners agreed increased frequency of patrols would be 
appropriate. MidAmerican noted patrols are a relatively low cost action 
that generates useful data.
    f. Shorter ILI intervals: MidAmerican opposed shorter intervals, 
noting many lines cannot accommodate in-line inspection or more 
frequent runs. The Wyoming County Commissioners argued that frequent 
assessment is a good practice that should be required.
    g. Additional gas quality monitoring: MidAmerican opposed such a 
requirement, arguing it would be redundant for distribution pipeline 
operators receiving gas from suppliers. The Wyoming County 
Commissioners argued frequent gas monitoring would be a good practice.
    h. Improved pipeline marking standards: MidAmerican agreed 
implementing new marking standards would be a low cost action. Wyoming 
County again noted this is a good practice.
    B.5. Should requirements for additional preventive and mitigative 
measures be established for pipeline segments not in HCAs? Should these 
requirements be the same as those for HCAs or should they be different? 
Should they apply to all pipeline segments not in HCAs or only to some? 
If not all, how should the pipeline segments to which new requirements 
apply be delineated?
    1. INGAA, supported by many of its member companies, argued 
preventive and mitigative measures should be applied to non-HCA areas 
on a risk basis rather than by prescriptive requirement. INGAA 
commented this is a more effective and efficient means of increasing 
pipeline safety.
    2. AGA commented codifying different requirements for non-HCA areas 
would likely cause confusion and extending existing IM requirements to 
non-HCA areas would create an enormous burden for PHMSA and states. AGA 
noted the NTSB has already questioned the ability of regulators to 
apply the existing IM inspection protocols to HCA mileage. AGA 
recommended one-call and the actions required by statute be the only 
additional measures required system-wide.
    3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association, 
and two pipeline operators opposed requirements for preventive and 
mitigative actions in non-HCA areas. These commenters argued it is 
important to allow pipeline operators the flexibility to select actions 
that are appropriate to their circumstances and implementing actions 
required arbitrarily would be expensive and ineffective.
    4. Northern Natural Gas suggested PHMSA expand the HCA definition 
gradually over time rather than imposing IM requirements outside HCA. 
Northern commented such an approach would retain and expand the focus 
on areas posing the highest risk.
    5. MidAmerican opposed additional requirements for preventive and 
mitigative actions, noting all pipeline is covered by other 
requirements in part 192 and it is better to focus enhanced 
requirements on areas posing highest risk.
    6. AGA commented measures required in HCA should always be equal to 
or more stringent than measures required outside of HCA. AGA noted this 
is a fundamental principle of integrity management: Focusing on areas 
posing higher risks.
    7. Ameren Illinois and an anonymous commenter suggested better 
enforcement and/or specificity for provisions requiring operators 
consider other areas of their systems when problems are discovered 
would be more effective than requiring preventive and mitigative 
measures outside HCA.
    8. ITT Exelis Geospatial Systems commented requirements should be 
the same in- or outside HCA. They contended non-HCA areas are not 
monitored for leakage as often as Class 3 and 4 locations. They 
suggested their LIDAR system would allow effective and efficient leak 
surveys in all locations.
    9. A public citizen recommended exposed pipe be wrapped in bright 
colors and protected from damage whether inside or outside of HCA. The 
commenter suggested analysis of data from CGA's Damage Information 
Reporting Tool would be an effective preventive measure.
    B.6. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible.

[[Page 20754]]

In addition, PHMSA requests commenters to provide information and 
supporting data related to, among other factors, the potential costs of 
modifying the existing regulatory requirements pursuant to the 
commenter's suggestions.
    1. Northern Natural Gas reported the additional cost of 
preventative and mitigative measures it employs, including instrumented 
aerial leakage surveys, close-interval surveys, additional mailings and 
additional signage, has been approximately $950,000. Northern further 
reported the approximate cost of conducting assessments through in-line 
inspection or pressure testing for all high-consequence areas every 
seven years is $45,000,000 and reduction of the inspection interval 
would increase the cost accordingly.
Response to Topic B comments
    Section 5 of the Act requires that the Secretary of Transportation 
complete an evaluation and issue a report on whether integrity 
management requirements should be expanded beyond HCAs and whether such 
expansion would mitigate the need for class location requirements. 
Aspects of this topic that relate to applying a risk analysis to 
determine additional preventive and mitigative measures for non-HCA 
pipeline segments will be addressed later, pending completion of the 
evaluation and report. PHMSA will review the comments received on this 
topic and will address them in the future in light of these statutory 
requirements.
    Section 3 of the Act requires that the Secretary of Transportation 
complete an evaluation and issue a report on the impact of excavation 
damage on pipeline safety. Aspects of this topic that relate to 
additional preventive and mitigative measures for damage prevention 
will be addressed after completion of the evaluation and report. PHMSA 
will review the comments received on this topic and will address them 
in the future in light of this evaluation and report.
    Section 6 of the Act requires that the Secretary of Transportation 
provide guidance on public awareness and emergency response plans. 
Aspects of this topic that relate to additional preventive and 
mitigative measures for public awareness and emergency response will be 
further evaluated in conjunction with this statutory mandate. PHMSA 
will review the comments received on this topic and will address them 
in the future in light of this evaluation.
    Two specific areas of preventive and mitigative actions addressed 
in the IM requirements (49 CFR 192.935) are leak detection and 
automatic/remote control valves. The IM rule does not require specific 
measures be taken to address these aspects of pipeline design and 
operations, but does include them among candidate preventive and 
mitigative measures operators should consider. Both of these topics are 
the subject of recommendations that the NTSB made (recommendations P-
11-10 and P-11-11) following the San Bruno explosion. In response to 
these recommendations, PHMSA conducted a public workshop on March 27, 
2012, to seek stakeholder input on these issues, and is sponsoring 
additional research and development to further inform PHMSA's response 
on these issues. Aspects of this topic that relate to leak detection 
and automatic/remote control valves will be addressed after completion 
and evaluation of the above activities. PHMSA will review the comments 
received on leak detection and automatic/remote control valves and will 
address them in the future in light of this evaluation.
    PHMSA is proposing to add requirements for enhanced preventive and 
mitigative measures to address internal and external corrosion control. 
The intent of the IM rulemaking is to enhance protections for high 
consequence areas. PHMSA believes that enhanced requirements for 
internal corrosion and external corrosion control are prudent. To 
address internal corrosion, PHMSA is proposing specific requirements 
for operators to monitor gas quality and contaminants and to take 
actions to mitigate adverse conditions. To address external corrosion, 
PHMSA is proposing specific requirements for operators to monitor and 
confirm the effectiveness of external corrosion control through 
electrical interference surveys and indirect assessments, including 
cathodic protection surveys and coating surveys, to take actions needed 
to mitigate conditions that are unfavorable to effective cathodic 
protection, and to integrate the results of these surveys with 
integrity assessment and other integrity-related data. PHMSA addresses 
this topic in more detail in response to comments related to Topic I, 
Corrosion Control.

    Note: Specific comments submitted for Topic B that are related 
to risk and integrity assessments are addressed under Topics E and 
G.

C. Modifying Repair Criteria

    The existing integrity management regulations establish criteria 
for the timely repair of injurious anomalies and defects discovered in 
the pipe (49 CFR 192.933). These criteria apply to pipeline segments in 
an HCA, but not to segments outside an HCA. The ANPRM announced that 
PHMSA is considering amending the integrity management rule by revising 
the repair criteria to provide greater assurance that injurious 
anomalies and defects are repaired before the defect can grow to a size 
that leads to a leak or rupture. In addition, PHMSA is considering 
establishing repair criteria for pipeline segments located in areas 
that are not in an HCA in order to provide greater assurance that 
defects on non-HCA pipeline segments are repaired in a timely manner. 
The following are general comments received related to the topic and 
then comments related to the specific questions:
General Comments for Topic C
    1. INGAA reported its members' commitment to apply ASME/ANSI B31.8S 
corrosion anomaly criteria both inside and outside of HCAs. INGAA noted 
that new research to refine and extend the technical bases for 
responding to corrosion anomalies identified primarily by ILI has been 
completed by Pipeline Research Council International, whose report was 
expected to be published in the first quarter of 2012. INGAA also 
reported a commitment to develop and use criteria for mitigation of 
dents, corrosion pitting, expanded pipe corrosion, and selective seam 
weld corrosion. Numerous pipeline operators supported INGAA's comments.
    2. AGA suggested that ASME/ANSI B31.8S should be the basis for 
defining anomalies requiring remediation. Anomalies not meeting the 
criteria in that standard, in AGA's opinion, do not require repair. AGA 
further commented that risk prioritization of maintenance and anomaly 
response should not be regulated because operators are in the best 
position to know the factors influencing prioritization for apparently-
similar anomalies. AGA also suggested that PHMSA review INGAA's paper 
``Anomaly Response and Mitigation Outside of High Consequence Areas 
when Using in Line Inspection,'' dated May 30, 2010, as this paper 
forms the basis for current industry response outside of HCAs. Numerous 
pipeline operators supported AGA's comments.
    3. Accufacts contended that there have been too many corrosion-
caused ruptures occurring shortly after in-line

[[Page 20755]]

inspection runs and that this indicates the need for more prescriptive 
criteria for corrosion evaluation and remediation.
    4. Alaska Department of Natural Resources commented that repairs 
should be made using permanent methods, and that clamps and similar 
repairs are not sufficient.
Response to General Comments for Topic C
    PHMSA appreciates the information provided by the commenters. 
Because the current repair criteria only address corrosion metal loss 
as an immediate condition, PHMSA agrees that more prescriptive repair 
criteria are needed to address significant corrosion metal loss that 
does not meet the immediate repair criterion, similar to the hazardous 
liquid integrity management repair criteria at 49 CFR 195.452(h). In 
addition, other conditions that are not currently addressed in the 
repair criteria, such as stress corrosion cracking and selective seam 
weld corrosion, are addressed in ASME B31.8S and other sources, but not 
explicitly addressed in part 192. PHMSA is proposing to enhance the 
repair criteria for HCA segments and is also proposing to add specific 
repair criteria for pipeline in non-HCA segments. In general, PHMSA is 
proposing to add more immediate repair conditions and more one-year 
conditions for HCA segments. The additional criteria address conditions 
not previously addressed, such as stress corrosion cracking, and also 
include more specific one-year criteria for corrosion metal loss, based 
on the design factor for the class location in which the pipeline is 
located, to address corrosion metal loss that reduces the design safety 
factor of the pipe. PHMSA is also proposing to apply similar repair 
criteria in non-HCA segments, except that response times will be 
tiered, with longer response times for non-immediate conditions. PHMSA 
reviewed available industry literature, including ASME/ANSI B31.8S, in 
developing the proposed repair criteria. Specific aspects of the 
proposed rules are discussed in response to the specific questions for 
Topic C, below.
    PHMSA has not addressed the specific procedures and techniques for 
performing repairs in this rulemaking, but may do so at a later date.
Comments Submitted for Questions in Topic C
    C.1. Should the immediate repair criterion of failure pressure 
ratio (FPR) <=1.1 be revised to require repair at a higher threshold 
(i.e., additional safety margin to failure)? Should repair safety 
margins be the same as new construction standards? Should class 
location changes, where the class location has changed from Class 1 to 
2, 2 to 3, or 3 to 4 without pipe replacement have repair criteria that 
are more stringent than other locations? Should there be a metal loss 
repair criterion that requires immediate or a specified time to repair 
regardless of its location (HCA and non-HCA)?
    1. INGAA, supported by numerous pipeline operators, commented the 
FPR criterion need not be changed, noting there have been no reported 
incidents due to the criterion being too lax. INGAA also objected to 
PHMSA's characterization of this issue, noting that repair criteria 
already exceed 1.1 FPR; the 1.1 FPR criterion in the regulations 
governs response to anomalies and not the criteria to which repairs 
must be made.
    2. AGA, supported by numerous of its pipeline operator members, 
commented that the FPR criterion should not be changed. AGA contended 
that the criterion already provides a 10 percent safety margin and is 
based on sound engineering practices.
    3. Northern Natural Gas and Kern River stated that conservatism is 
present in burst pressure calculations and in the measurement of 
anomalies (considering tool tolerance), providing a safety margin 
greater than 10 percent.
    4. Accufacts argued against changing the FPR criterion, but 
suggested that PHMSA require operators to use better assumptions in 
their failure analyses. Accufacts suggested that the regulations should 
focus on preventing failures but that existing safety margins need not 
be increased.
    5. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, 
and MidAmerican opposed changes to this criterion. These commenters 
noted that experience through the baseline inspections has demonstrated 
the criterion is adequate and ASME/ANSI B31.8S remains a good guide for 
anomaly response. Atmos added that this criterion separates immediate 
repairs from scheduled repairs: It allows a risk-based focus on more 
serious anomalies but does not mean that anomalies providing more than 
10 percent margin to burst pressure are never addressed.
    6. California Public Utilities Commission suggested that the FPR 
criterion be increased to 1.25 times MAOP. CPUC noted that the 10 
percent margin in the current criterion can be completely erased by the 
10 percent margin to safety relief settings allowed by Sec.  192.201.
    7. INGAA commented that additional repair criteria are not needed. 
INGAA noted that Sec. Sec.  192.485(a) and 192.713(a) already specify 
repair criteria applicable to pipe outside HCA. Numerous pipeline 
operators supported INGAA's comments.
    8. AGA, supported by numerous of its pipeline operator members, 
suggested that safety margins for repairs need not be the same as those 
for new construction. AGA argued that the construction margins are 
intended to address potential unknowns and forces applied during 
construction, which are not applicable to repairs.
    9. Accufacts, Northern Natural Gas, and an anonymous commenter 
agreed that repairs, once initiated, should meet new construction 
safety margins.
    10. INGAA and several of its pipeline operator members argued that 
repair criteria should not be more stringent where class location has 
changed. INGAA noted that Sec.  192.611 does not change the original 
design criteria for segments that have been subject to a change in 
class location and there is no incident experience suggesting that 
additional safety margin is needed in these cases.
    11. Northern Natural Gas and Kern River argued against a change in 
repair criteria where class location has changed, noting that the 
likelihood of failure of an anomaly is not affected by the class 
location and that treatment in accordance with integrity management 
requirements already considers risk.
    12. MidAmerican, Paiute, and Southwest Gas added that use of the 
factor failure pressure divided by MAOP in ASME/ANSI B31.8S already 
reflects any change in MAOP necessitated by a change in class location.
    13. Accufacts commented that repair criteria should be commensurate 
with the more restrictive design criteria of higher class locations.
    14. INGAA commented no new metal loss criterion is needed, noting 
that its members use HCA response criteria as a guide for responding to 
indications of metal loss outside of HCAs. Numerous pipeline operators 
supported INGAA's comments.
    15. AGA commented any metal loss criterion should reflect current 
science and should be the same regardless of class location. AGA 
suggested that immediate response to any indication of a dent with 
metal loss is not needed, noting that there have been many examples of 
dents with metal loss not sufficient to require recalculating remaining 
strength. AGA also noted the external corrosion direct assessment 
standard requires a similar response regardless of whether an 
indication is in

[[Page 20756]]

or outside HCA. Numerous pipeline operators supported AGA's comments.
    16. Accufacts encouraged PHMSA to establish a prompt-action 
criterion for wall loss inside or outside HCAs, suggesting the focus 
should be on preventing ruptures regardless of where they occur. 
Accufacts also cautioned PHMSA against accepting studies attempting to 
show that 80 percent wall loss is sometimes acceptable, and stated that 
continued operation with such wall loss is too risky for onshore 
pipelines.
Response to Question C.1 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of comments supported no changes to the immediate repair 
criterion of predicted failure pressure of less than or equal to 1.1 
times MAOP for HCAs, and PHMSA is not proposing to change this 
criterion; however, PHMSA is proposing several changes to enhance the 
repair criteria both for HCA segments and non-HCA segments. For 
immediate conditions, PHMSA proposes to add the following to the 
immediate repair criteria: Metal loss greater than 80% of nominal wall 
thickness, indication of metal-loss affecting certain types of 
longitudinal seams, significant stress corrosion cracking, and 
selective seam weld corrosion. These additional repair criteria would 
address specific issues or gaps with the existing criteria. The methods 
specified in the IM rule to calculate predicted failure pressure are 
explicitly not valid if metal loss exceeds 80% of wall thickness. 
Corrosion affecting a longitudinal seam, especially associated with 
seam types that are known to be susceptible to latent manufacturing 
defects such as the failed pipe at San Bruno, and selective seam weld 
corrosion are known near-term integrity threats. Stress corrosion 
cracking is listed in ASME B31.8S as an immediate repair condition, 
which is not reflected in the current IM regulations. PHMSA proposes to 
add requirements to address these gaps.
    The current regulations include no explicit metal loss repair 
criteria, other than one immediate condition. The regulations direct 
operators to use Figure 4 in ASME B31.8S to determine non-immediate 
metal loss repair criteria. PHMSA now proposes to explicitly include 
selected metal loss repair conditions in the one-year criteria. These 
proposed criteria are consistent with similar criteria currently 
invoked in the hazardous liquid integrity management rule at 40 CFR 
195.452(h). In addition, PHMSA proposes to incorporate safety factors 
commensurate with the class location in which the pipeline is located, 
to include predicted failure pressure less than or equal to 1.25 times 
MAOP for Class 1 locations, 1.39 times MAOP for Class 2 locations, 1.67 
times MAOP for Class 3 locations, and 2.00 times MAOP for Class 4 
locations in HCAs. Lastly, in response to the lessons learned from the 
Marshall, Michigan, rupture, PHMSA proposes to include any crack or 
crack-like defect that does not meet the proposed immediate criteria as 
a one year condition. PHMSA proposes to apply these same criteria as 
two-year conditions for non-HCAs.
    PHMSA agrees with Accufacts' comment that the regulations should 
focus on preventing failures but that existing safety margins are 
adequate when properly applied. Therefore, the proposed rule does not 
propose to increase safety margins such as the design factor. PHMSA 
maintains that the proposed changes discussed above provide a tiered, 
risk-based approach to metal loss repair criteria and by requiring 
predicted failure pressures as a function of class locations does not 
compound safety margins. Counter to INGAA's and AGA's comments that 
repair criteria should not be more stringent where class location has 
changed, PHMSA believes the tiered approach to metal loss repair 
criteria, which is a function of class location, provides a logical 
framework to address the risk presented by these types of pipeline 
anomalies.
    In conjunction with enhanced repair criteria, PHMSA is proposing 
specific new regulations to require that operators properly analyze 
uncertainties and other factors that could lead to non-conservative 
predictions of failure pressure, and time remaining to failure, when 
evaluating ILI anomaly indications. PHMSA specifically is proposing 
that operators must analyze specific known sources of uncertainty 
regarding ILI tool performance, anomaly interactions, and other sources 
of uncertainty when determining if an anomaly meets any repair 
criterion.
    C.2. Should anomalous conditions in non-HCA pipeline segments 
qualify as repair conditions subject to the IM repair schedules? If so, 
which ones? What projected costs and benefits would result from this 
requirement?
    1. INGAA suggested that new criteria are not needed, commenting 
that operators generally treat non-HCA anomalies in a manner similar to 
HCA anomalies, except for response time. INGAA stated that industry 
costs to address non-HCA anomalies should be nominal unless immediate 
response is required because this is consistent with current operator 
practice, which INGAA stated is to apply ASME/ANSI B31.8S response 
criteria for anomalies both inside and outside HCAs.
    2. Texas Pipeline Association and Texas Oil & Gas Association 
commented that differing repair criteria, if any, should be based upon 
the population at risk, since there is no valid engineering basis for 
treating anomalies differently depending on location.
    3. Atmos and Northern Natural Gas suggested that non-HCA anomalies 
should be treated like HCA anomalies, although additional schedule 
flexibility should be allowed. Northern reported that it applies HCA 
metal loss criteria everywhere because it is prudent, although response 
time differs for non-HCA anomalies. Northern reported that it has 
expended approximately $7.7 million on anomaly repairs, $7 million of 
which was outside an HCA.
    4. Kern River agreed that IM schedules are too stringent to apply 
everywhere and providing schedule flexibility will reduce costs.
    5. MidAmerican disagreed with the suggestion that non-HCA and HCA 
anomalies be treated alike. MidAmerican commented that it is illogical 
to back off from focusing sooner on anomalies that pose greater risks.
    6. California Public Utilities Commission commented that all 
locations identified by the method described in paragraph 1 in the 
definition of HCA in Sec.  192.903 should be subject to HCA repair 
criteria.
    7. Pipeline Safety Trust, Accufacts, and NAPSR commented that the 
same repair criteria and response schedule should apply regardless of 
where an anomaly is located. These commenters contended that there is 
no logical justification for different treatment, that any risk to the 
pipeline and public safety should be resolved, and that a pipeline 
accident anywhere is seen by the public as a failure to exercise 
adequate control of pipeline safety. NAPSR, in particular, suggested 
that all anomalies should be repaired immediately, regardless of where 
they are located.
    8. Iowa Utilities Board, Iowa Association of Municipal Utilities, 
GPTC, Nicor, Ameren Illinois and an anonymous commenter contended that 
HCA repair criteria should not be applied outside HCAs. These 
commenters noted that there has been no demonstrated safety need for 
new criteria, that non-HCA anomalies are adequately addressed under 
existing operations and maintenance requirements, and that the cost to 
apply HCA repair criteria everywhere is not justified. IAMU 
particularly noted that

[[Page 20757]]

existing requirements are adequate for small, low-pressure transmission 
pipelines such as those operated by its members.
    9. A private citizen supported application of HCA repair criteria 
in non-HCA areas, particularly where there are ``receptors,'' which the 
commenter defines as ``something which needs to be protected.''
Response to Question C.2 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
proposes to modify the general requirement for repair of pipelines to 
include immediate repair condition criteria, one-year conditions, and 
monitored conditions. The definition of these conditions would be the 
same as the existing definitions for covered segments (i.e., HCA 
segments) in the IM rule; however, PHMSA proposes that those conditions 
that must be repaired within one year in a HCA segment would be 
required to be repaired within two years in a non-HCA segment. Defects 
that meet any of the immediate criteria are considered to be near-term 
threats to pipeline integrity and would be required to be repaired 
immediately regardless of location.
    PHMSA believes that establishing these non-HCA segment repair 
conditions are important because, even though they are not within the 
defined high consequence locations, they could be located in populated 
areas and are not without consequence. For example, as reported by 
operators in the 2011 annual reports, while there are approximately 
20,000 miles of gas transmission pipe in HCA segments, there are 
approximately 65,000 miles of pipe in Class 2, 3, and 4 populated 
areas. PHMSA believes it is prudent and appropriate to include criteria 
to assure the timely repair of injurious pipeline defects in non-HCA 
segments. These changes will ensure the prompt remediation of anomalous 
conditions on all gas pipeline segments while allowing operators to 
allocate their resources to high consequence areas on a higher priority 
basis.
    C.3. Should PHMSA consider a risk tiering--where the conditions in 
the HCA areas would be addressed first, followed by the conditions in 
the non-HCA areas? How should PHMSA evaluate and measure risk in this 
context, and what risk factors should be considered?
    1. INGAA, and many pipeline operators, opposed the suggested 
tiering. They commented that anomalies meeting response criteria should 
be addressed in an appropriate time frame whether inside or outside 
HCAs.
    2. AGA, supported by many of its operator members, suggested that 
PHMSA not adopt any risk tiering beyond the current requirements to 
focus first on HCA anomalies. AGA noted that outside factors, e.g., 
permitting, affect the timing and the sequence of repairs.
    3. Texas Pipeline Association and Texas Oil & Gas Association 
commented that PHMSA should allow risk tiering system-wide, not just in 
differentiating between responses in and outside HCA. The associations 
suggested that this could be an improvement to requirements addressing 
anomalies. At the same time, they noted the description in the ANPRM is 
sketchy and requested PHMSA propose specific requirements for comment.
    4. Iowa Association of Municipal Utilities commented that no new 
requirements are needed, and that the existing requirements are 
sufficient for the small, low-stress transmission pipelines operated by 
its members.
    5. Atmos commented that the risk tiering concept is confusing and 
stated that it was considered and rejected when the initial IM rules 
were promulgated.
    6. Northern Natural Gas commented that allowing a longer response 
time for anomalies outside HCA would be a form of risk tiering. The 
company reported it has incorporated this practice in its procedures.
    7. Accufacts agreed that a focus on HCA anomalies is needed but 
cautioned against ignoring anomalies outside HCAs. Accufacts noted the 
progression of an anomaly to failure does not depend on whether or not 
it is located in an HCA.
Response to Question C.3 Comments
    PHMSA appreciates the information provided by the commenters. 
Current regulations do not prescribe response timeframes for anomalies 
outside HCAs. As stated by Northern Natural Gas, allowing a longer 
response time for anomalies outside HCAs (compared to response times 
for anomalies inside HCAs) would be a form of risk-tiering. PHMSA is 
proposing such an approach, which would establish three timeframes for 
performing repairs in non-HCA areas: Immediate repair conditions, 2-
year repair conditions, and monitored conditions. These changes will 
ensure the prompt remediation of anomalous conditions on all gas 
pipeline segments, while allowing operators to allocate their resources 
to those areas that present a higher risk.
    C.4. What should be the repair schedules for anomalous conditions 
discovered in non-HCA pipeline segments through the integrity 
assessment or information analysis? Would a shortened repair schedule 
significantly reduce risk? Should repair schedules for anomalous 
conditions in HCAs be the same as or different from those in non-HCAs?
    1. INGAA commented that repair schedules outside HCAs should be 
similar to those in HCAs but should allow for more scheduling latitude. 
This comment was supported by comments received from many of its 
operator members. They also noted that adding requirements to repair 
non-HCA anomalies would significantly increase the number of required 
repairs and that an inappropriate requirement for rapid response would 
dilute the focus on risk-significant repairs. INGAA suggested that 
repair schedules should be more a function of anomaly growth rates than 
location along the pipeline. INGAA further suggested that 
inappropriately rapid response schedules would increase risk; 
experience shows that most anomalies that have been found and repaired 
are old, do not require a rapid response, and that mandating rapid 
response to such anomalies would necessarily dilute other safety 
activities.
    2. Texas Pipeline Association and Texas Oil & Gas Association 
expressed doubt that significant risk reduction would result from 
shortened repair schedules, given the logistics and related work 
involved in repairs.
    3. GPTC, Nicor, and an anonymous commenter objected to applying HCA 
repair criteria outside HCAs. They believe that the costs for such an 
approach are not justified and non-HCA anomalies are appropriately 
dealt with under operations and maintenance requirements and 
procedures.
    4. Ameren Illinois, Paiute, and Southwest Gas agreed that 
prescriptive repair schedules are not needed outside HCAs. They 
expressed a belief that operators must have scheduling flexibility to 
accommodate the needs of their operations.
    5. MidAmerican suggested that immediate repair criteria be applied 
both in HCAs and outside HCAs, but that other criteria be limited to 
HCAs.
    6. Northern Natural Gas suggested that PHMSA should require 
operators to determine response schedules for non-HCA anomalies as part 
of this rulemaking.
    7. Iowa Association of Municipal Utilities commented that the 
existing requirements are sufficient for the small, low-stress 
transmission pipelines operated by its members.
    8. California Public Utilities Commission commented that all method

[[Page 20758]]

1 HCA locations should be subject to HCA repair criteria.
    9. MidAmerican, Paiute, and Southwest Gas commented that shortened 
response schedules will not reduce risk. These operators suggested that 
response times should be based on risk rather than being established 
arbitrarily.
Response to Question C.4 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
believes repair schedules outside HCAs should be similar to those in 
HCAs but should allow for more scheduling latitude. PHMSA proposes to 
establish three timeframes for remediating defects in non-HCA areas: 
Immediate repair conditions, 2-year repair conditions (rather than one-
year for HCAs), and monitored conditions. These changes will ensure the 
prompt remediation of anomalous conditions on all gas pipeline 
segments, commensurate with risk, while allowing operators to allocate 
their resources to those areas that present a higher risk.
    C.5. Have ILI tool capability advances resulted in a need to update 
the ``dent with metal loss'' repair criteria?
    1. INGAA commented that ILI tool capabilities have improved to the 
point where it is appropriate to revise the dent-with-metal loss 
criterion. This comment was supported by comments received from many of 
its operator members. INGAA suggested that Section 851.4(f) of ASME/
ANSI B31.8 provides appropriate guidance in this area.
    2. AGA suggested that it would be appropriate to eliminate the 
immediate response criterion for ``dent with metal loss.'' This comment 
was supported by comments received from many of its operator members. 
They commented that industry experience has shown that many dents do 
not require immediate repair.
    3. Texas Pipeline Association, Texas Oil & Gas Association, 
MidAmerican, Paiute, Southwest Gas, and Atmos supported revising this 
criterion. These commenters noted that improvements in ILI allow better 
distinction between a gouge and corrosion wall loss. MidAmerican 
further commented that there are problems with implementing Sec.  
192.933 as written.
    4. Northern Natural Gas stated that it would support treating these 
anomalies as mechanical damage, and suggested that this would simplify 
the regulations.
    5. Ameren Illinois suggested further study of this proposal taking 
into account current ILI technology.
    6. Accufacts and an anonymous commenter opposed changes to this 
criterion. These commenters suggested that ILI is still not adequate to 
determine reliably the time to failure of this compound threat.
    7. GPTC and Nicor suggested that PHMSA consider updating the Dent 
Study technical report \35\ that discusses reliability and application 
of ILI.
---------------------------------------------------------------------------

    \35\ Baker and Kiefner & Associates, ``Dent Study Technical 
Report,'' (November 2004, OPS TTO Number 10, available at http://primis.phmsa.dot.gov/gasimp/techreports.htm).
---------------------------------------------------------------------------

Response to Question C.5 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
is not proposing to update the dent-with-metal-loss criterion at this 
time. PHMSA will continue to evaluate this criterion, including 
consideration of additional research to better define the repair 
criteria for this specific type of defect.
    C.6. How do operators currently treat assessment tool uncertainties 
when comparing assessment results to repair criteria? Should PHMSA 
adopt explicit voluntary standards to account for the known accuracy of 
in-line inspection tools when comparing in-line inspection tool data 
with the repair criteria? Should PHMSA develop voluntary assessment 
standards or prescribe ILI assessment standards including wall loss 
detection threshold depth detection, probability of detection, and 
sizing accuracy standards that are consistent for all ILI vendors and 
operators? Should PHMSA prescribe methods for validation of ILI tool 
performance such as validation excavations, analysis of as-found versus 
as-predicted defect dimensions? Should PHMSA prescribe appropriate 
assessment methods for pipeline integrity threats?
    1. INGAA, supported by many of its member companies, reported that 
operators use many methods to accommodate ILI uncertainties, not simply 
adding tool tolerance to results. INGAA suggested API-1163, In-line 
Inspection Systems Qualification Standard, as an appropriate guide. 
INGAA noted this standard is non-prescriptive; INGAA expressed its 
belief prescriptive standards would stifle innovation. INGAA also 
reported that ASME has plans to update its standard on ``Gas 
Transmission and Distribution Piping Systems,'' ASME/ANSI B31.8S, 
regarding treatment of uncertainties based on the results of Pipeline 
Research Council International (PRCI) research that was underway at the 
time comments were submitted.
    2. AGA and a number of pipeline operators suggested that tool 
tolerances should be added to ILI results.
    3. Texas Pipeline Association, Texas Oil & Gas Association, and 
Atmos reported their understanding that most operators follow ASME/ANSI 
B31.8S as a guide.
    4. Northern Natural Gas and Kern River expressed their conclusion 
that PHMSA's Gas Integrity Management Program Frequently Asked Question 
FAQ-68 provides sufficient guidance on the treatment of uncertainties 
(FAQs can be viewed at http://primis.phmsa.dot.gov/gasimp/faqs.htm). 
They noted that technology is developing rapidly in this area, which 
they imply is a reason not to impose prescriptive requirements.
    5. Texas Pipeline Association and Texas Oil & Gas Association 
agreed that prescriptive requirements should not be imposed, because 
the rapidly-developing technology would soon render them obsolete.
    6. GPTC, Nicor, MidAmerican, and Atmos argued that prescriptive 
methods for validating tool performance are not an appropriate subject 
for regulation.
    7. Ameren Illinois commented that it sees no technical 
justification for establishing requirements in this area.
    8. Accufacts suggested that PHMSA specify minimum standards for ILI 
validation, including specifying a required number of digs. Alaska 
Department of Natural Resources and California Public Utilities 
Commission took a similar stance, all arguing that standards assure 
public confidence and consistency of results.
    9. A private citizen commented that voluntary standards are not 
sufficient because they cannot be enforced.
    10. An anonymous commenter recommended against adopting 
requirements for treatment of inaccuracies. The commenter opined that 
operators are doing better in this area, contending that smaller 
operators, in particular, needed time to learn. The commenter suggested 
that specific rules would set many operators back.
    11. INGAA and many of its pipeline operators commented that 
incorporating standards into part 192 that compete with industry 
standards would be counterproductive. INGAA noted that API-1163, API-
579-1, Fitness-for-Service, and ASNT ILI-PQ, In-Line Inspection 
Personnel Qualification and Certification Standard, are already in wide 
use and contended specifying standards in the regulations would stifle 
further development.
    12. GPTC and Nicor agreed with INGAA, noting that the regulatory 
approval process cannot keep up with technological development.
    13. Northern Natural Gas recommended that PHMSA not adopt standards 
for addressing ILI inaccuracies, contending the many

[[Page 20759]]

different tools currently in use would make this impractical.
    14. MidAmerican reported its belief that operators have sufficient 
incentive to work with ILI vendors to assure appropriate validation of 
ILI results.
    15. Paiute and Southwest Gas argued against adoption of regulatory 
standards to treat ILI uncertainties, noting that this subject is 
already addressed in ASME/ANSI B31.8S.
    16. AGA, supported by a number of its member companies, suggested 
that PHMSA should not prescribe IM methods, noting that operators have 
demonstrated the ability to conduct assessments without them.
    17. Accufacts, Alaska Natural Gas Development Authority, and 
California Public Utilities Commission argued for requirements 
prescribing assessment methods for various threats. These commenters 
suggested that such requirements would be a bridge to better risk 
management strategies and contended that there is currently an over-
reliance on direct assessment.
Response to Question C.6 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of comments do not support adopting explicit standards or 
analytical methodologies to account for the known accuracy of in-line 
inspection tools. PHMSA concurs that prescriptive rules to account for 
the accuracy of in-line inspection tools is not practical, however it 
is beneficial to all to clarify PHMSA's expectations with respect to 
current performance-based regulations in this area which specify that 
internal inspection may be used to identify and evaluate potential 
pipeline threats. Therefore, PHMSA proposes to add detailed 
performance-based rule language to require that operators using ILI 
must explicitly consider uncertainties in reported results (including 
tool tolerance, anomaly findings, and unity chart plots or equivalent 
for determining uncertainties) in identifying anomalies. While ASME/
ANSI B31.8S discusses uncertainties, PHMSA believes it will improve the 
visibility and emphasis on this important issue to explicitly address 
uncertainties in the rule text.
    C.7. Should PHMSA adopt standards for conducting in-line 
inspections using ``smart pigs,'' the qualification of persons 
interpreting in-line inspection data, the review of ILI results 
including the integration of other data sources in interpreting ILI 
results, and/or the quality and accuracy of in-line inspection tool 
performance, to gain a greater level of assurance that injurious 
pipeline defects are discovered? Should these standards be voluntary or 
adopted as requirements?
    1. AGA and its pipeline operator members argued against the 
adoption of standards. AGA commented that voluntary use has proven to 
be sufficient and expressed its position that consensus standards 
should not be adopted into regulations until widespread experience has 
been gained with their use. AGA contended that premature adoption would 
stifle technological innovation.
    2. INGAA and many of its members commented that PHMSA's process for 
review and adoption of standards must be streamlined if existing 
consensus standards are incorporated into regulations. Such 
improvements, INGAA contended, would assure that standard improvements 
are adopted without delay.
    3. An anonymous commenter, GPTC, and Nicor cited similar concerns 
in suggesting that standards not be adopted into regulations, 
contending that the rulemaking process cannot keep up with 
technological change.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
objected to the adoption of ILI standards in regulations, contending 
that voluntary use is more appropriate.
    5. MidAmerican commented that operator qualification requirements 
should be applied to ILI, as this would provide higher assurance of 
defect discovery. Beyond this, however, MidAmerican contended that the 
use of consensus standards should remain voluntary, as this allows the 
operator to select those standards most appropriate to its 
circumstances.
    6. Paiute and Southwest Gas objected to the incorporation of ILI 
standards into regulations. The companies expressed a belief that there 
is no technical basis for doing so. They commented that the question, 
as posed in the ANPRM, implies that anomalies are not now being found 
and contended that there is no evidence to support this implication.
    7. A private citizen, Thomas Lael, and Alaska Department of Natural 
Resources commented that PHMSA should require operators to meet 
specified standards. Mr. Lael referred to an incident that occurred 
following a pipeline assessment conducted in Ohio in 2011; Mr. Lael 
contended that the reasons the incident cause was not identified by the 
assessment are unknown to the public.
    8. Pipeline Safety Trust commented that PHMSA should assure 
assessment tools are capable and are used properly.
    9. The NTSB recommended that PHMSA require all pipelines to be made 
piggable, giving priority to older lines, citing their recommendation 
P-11-17.
Response to Question C.7 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of industry comments do not support the incorporation of ILI 
standards into regulations. However, based on the information presented 
below, PHMSA has concluded that it is prudent to propose incorporating 
available consensus ILI standards into the regulations. The current 
pipeline safety regulations for integrity management of segments in 
HCAs contained in 49 CFR 192.921 and 192.937 require that operators 
assess the material condition of pipelines in certain circumstances and 
allow use of in-line inspection tools for these assessments. PHMSA 
proposes to incorporate similar requirements for non-HCA pipe segments 
in Sec.  192.710. Operators are required to follow the requirements of 
ASME/ANSI B31.8S in selecting the appropriate ILI tools. However, ASME 
B31.8S provides only limited guidance for conducting ILI assessments. 
At the time the integrity management rules were promulgated, there was 
no consensus industry standard that addressed performance of ILI. Three 
related standards have since been published: API STD 1163-2005, NACE 
SP0102-2010, and ANSI/ASNT ILI-PQ-2010. API-1163 serves as an umbrella 
document to be used with and complement the NACE and ASNT standards. 
These three standards have enabled service providers and pipeline 
operators to provide processes that will qualify the equipment, people, 
processes, and software utilized in the in-line inspection industry. 
The incorporation of these standards into pipeline safety regulations 
developed through best practices of the industry based on the 
experience of numerous operators will promote high quality and more 
consistent assessment practices. Therefore, PHMSA is proposing to 
incorporate these industry standards into the regulations to provide 
clearer guidance for conducting integrity assessments with in-line 
inspection. PHMSA will continue to evaluate the need for additional 
guidance for conducting integrity assessments.
    C.8. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements

[[Page 20760]]

pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

D. Improving the Collection, Validation, and Integration of Pipeline 
Data

    The ANPRM requested comments regarding whether more prescriptive 
requirements for collecting, validating, integrating and reporting 
pipeline data are necessary. The current IM regulations require that 
gas transmission pipeline operators gather and integrate existing data 
and information concerning their entire pipeline that could be relevant 
to pipeline segments in HCAs (Sec.  192.917(b)). Operators are then 
required to use this information in a risk assessment of the HCA 
segments (Sec.  192.917(c)) that must subsequently be used to determine 
whether additional preventive and mitigative measures are needed (Sec.  
192.935) and to define the intervals at which IM reassessments must be 
performed (Sec.  192.939). Operators' risk analyses and conclusions can 
only be as good as the information used to perform the analyses. On 
August 30, 2011, after the ANPRM was issued, the NTSB adopted its 
report on the gas pipeline accident that occurred on September 9, 2010, 
in San Bruno, California. Results from the NTSB investigation indicate 
that the pipeline operator's records regarding the physical attributes 
of the pipe segments involved in the incident were erroneous. NTSB 
recommendation P-11-19 recommended that PHMSA require IM programs be 
assessed to assure that they are based on clear and meaningful metrics. 
In addition, Section 23 of the Act requires verification to ensure that 
records accurately reflect the physical and operational characteristics 
of pipelines. PHMSA issued an Advisory Bulletin (76 FR 1504; January 
10, 2011) on this issue. The following are general comments received 
related to the topic as well as comments related to the specific 
questions:
General Comments for Topic D
    1. INGAA reported that it is presently working on data integration 
guidelines. INGAA cautioned that requirements in this area can be very 
costly, since they often necessitate redesign of existing data 
management systems.
    2. AGA commented that no records requirements would have prevented 
the San Bruno accident, and stated that verifying records does not 
assure completeness, as unknown parameters remain unknown.
    3. A private citizen suggested that PHMSA should require operators 
to identify segments where they lack knowledge of critical parameters. 
The commenter suggested that this could facilitate emergency 
communications and help prioritize pipe replacement programs.
Response to General Comments for Topic D
    PHMSA appreciates the information provided by the commenters. PHMSA 
is proposing to clarify requirements for collecting, validating, and 
integrating data. The current rule invokes ASME/ANSI B31.8S 
requirements for data collection and integration. To provide greater 
visibility and emphasis on this important aspect of integrity 
management, PHMSA is proposing to place these requirements in the rule 
text, rather than incorporating ASME/ANSI B31.8S by reference. The 
proposed requirements clarify PHMSA's expectations regarding the 
minimum list of data an operator must collect, and also includes 
performance-based language that requires the operator to validate data 
it will use to make integrity-related decisions, and require operators 
to integrate all such data in a way that improves the analysis. The 
proposed rule would also require operators to use reliable, objective 
data to the maximum extent practical. To the degree that subjective 
data from subject matter experts must be used, PHMSA proposes to 
require that an operator's program include specific integrity 
assessment and findings data for the threat features to compensate for 
subject matter expert (SME) bias. The importance of these aspects of 
integrity management was emphasized by both the NTSB (Recommendation P-
11-19) and Congress (The Act, Section 11(a)(4)).
Comments Submitted for Questions in Topic D
    D.1. What practices are now used to acquire, integrate and validate 
data (e.g., review of mill inspection reports, hydrostatic tests 
reports, pipe leaks and rupture reports) concerning pipelines? Are 
practices in place, such as excavations of the pipeline, to validate 
data?
    1. INGAA reported that its members have completed a concerted 
effort to validate pipeline historical records pursuant to PHMSA 
Advisory Bulletin 11-01 (issued January 10, 2011).
    2. Texas Pipeline Association and Texas Oil & Gas Association 
commented that there is no great benefit to be gained from adding a 
verification requirement for historical data to the regulations. The 
associations believe that most operators will correct their records 
when they become aware of errors regardless of how the erroneous 
information is discovered. The associations suggested that there could 
be value in validating databases against original records, since an 
underlying problem of the San Bruno accident was errors in transferring 
original records into a database.
    3. Ameren Illinois reported that it collects data on exposed pipe 
in accordance with Sec. Sec.  192.459 and 192.475.
    4. Northern Natural Gas and Kern River reported that their primary 
integration tool is integrity alignment sheets, which show the class 
location, profile, aerial photography, alignment and structure data, 
in-line inspection results, other integrity data, i.e., close-interval 
survey or pressure test results and pipe, coating and appurtenance 
data. Data is validated as opportunities arise.
    5. Paiute and Southwest Gas reported that they confirm the location 
and properties of its pipeline as opportunities arise; more data are 
collected as assessments are conducted.
    6. California Public Utilities Commission suggested that operators 
be explicitly required to obtain all historical records and that there 
be an officer statement that a thorough search for all records has been 
conducted.
    7. A private citizen commented on the lack of some historical data, 
implying that operators should be required to validate their knowledge 
of older pipelines.
    8. An anonymous commenter stated that older data is typically not 
validated.
    9. INGAA and AGA reported that pipeline operators take advantage of 
exposed pipe to collect and validate data on in-service pipelines. This 
includes excavations for ILI validation, those conducted as part of 
direct assessment, and removed or replaced pipelines. A number of 
pipeline operators provided comments supporting the comments of each 
association.
    10. GPTC and Nicor suggested that excavations not be required for 
the sole purpose of validating data, contending that the risks posed by 
such a requirement would outweigh any benefit obtained.

[[Page 20761]]

    11. MidAmerican reported that it validates information when 
pipeline is excavated and through its routine practices.
Response to Question D.1 Comments
    PHMSA appreciates the information provided by the commenters. See 
response to question D.4.
    D.2. Do operators typically collect data when the pipeline is 
exposed for maintenance or other reasons to validate information in 
their records? If discrepancies are found, are investigations conducted 
to determine the extent of record errors? Should these actions be 
required, especially for HCA segments?
    1. AGA, Paiute, and Southwest Gas reported that operators use 
exposed pipe as an opportunity to collect information. AGA further 
suggested, however, that PHMSA should not draft a rule governing these 
practices. AGA contended the circumstances of pipe exposures vary too 
much to be addressed by a regulatory requirement. AGA expressed its 
conclusion that the requirements in Sec.  192.605(b)(3) provide 
adequate guidance and that section 23 of the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011 provides additional 
guidance. AGA noted that operators investigate identified inaccuracies 
and errors. A number of other pipeline operators provided comments 
supporting AGA's comments.
    2. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, 
MidAmerican, and Ameren Illinois reported that operators typically 
collect information on pipe type and condition, but not on historical 
information and pipe specifications. They commented that collecting 
this information would require additional testing and pose operational 
impacts.
    3. Iowa Utilities Board and Iowa Association of Municipal Utilities 
commented that any new requirement should be limited to collecting 
readily obtainable data, principally that which can be determined 
visually. They suggested that the data elements in ANPRM questions D.1 
and D.3 go beyond what can readily be observed or obtained and it would 
be impractical to require this data to be collected during pipe 
exposures.
    4. California Public Utilities Commission commented that any new 
requirements to collect data during pipe exposures should address all 
instances of exposure rather than be limited to HCAs, noting that non-
HCA segments can become HCA segments due to changes in land use near 
the pipeline.
    5. Thomas Lael and Alaska Department of Natural Resources commented 
that operators should be required to collect specific data during pipe 
exposures. These commenters contended that not all operators currently 
collect available data during pipe exposures.
    6. MidAmerican, Paiute, and Southwest Gas commented that no new 
requirements are needed because the requirements in part 192 and 
guidance in ASME/ANSI B31.8S are sufficient.
    7. An anonymous commenter suggested that operators be required to 
collect data if they do not have enough information to analyze the 
risks of the pipeline segment.
Response to Question D.2 Comments
    PHMSA appreciates the information provided by the commenters. The 
expanded rule language does not impose new requirements for collecting 
specific data during pipe exposures, but the response to question D.4 
discusses proposed changes to collection and validation practices to 
improve data integration and risk assessment practices.
    D.3. Do operators try to verify data on pipe, pipe seam type, pipe 
mechanical and chemical properties, mill inspection reports, 
hydrostatic tests reports, coating type and condition, pipe leaks and 
ruptures, and operations and maintenance (O&M) records on a periodic 
basis? Are practices in place to validate data, such as excavation and 
in situ examinations of the pipeline? If so, what are these practices?
    1. AGA, GPTC, Nicor, Paiute, and Southwest Gas reported that 
operators do try to verify information but that operator practices are 
too numerous to list in response to this general question. They 
contended that the requirements for external corrosion control in Sec.  
192.459 and for internal corrosion control in Sec.  192.475 and the 
guidance in Advisory Bulletin 11-01 are sufficient and no new 
requirements are needed. A number of other pipeline operators provided 
comments supporting AGA's comments.
    2. INGAA, supported by many of its pipeline operator members, 
commented that there are limited, if any, methods to determine 
accurately mechanical properties of pipe that is in situ. INGAA's 
comments listed a number of methods that can be used to obtain 
approximate values for some pipe characteristics, such as steel 
hardness and yield strength.
    3. Texas Pipeline Association and Texas Oil & Gas Association 
commented that operators do not validate mill data after initial 
construction.
    4. Ameren Illinois reported that data review and correction is a 
normal part of the business of pipeline operation. Ameren commented 
that additional work in this area is likely to result from Advisory 
Bulletin 11-01.
    5. Northern Natural Gas reported that data correction occurs when a 
discrepancy is identified. Northern also noted that it has added data 
to its risk model over time, principally related to determination of 
the potential consequences of a pipeline accident.
    6. MidAmerican commented that operators validate pipeline 
information periodically.
    7. California Public Utilities Commission reported that California 
pipeline operators have begun validating pipeline data since the San 
Bruno accident. CPUC commented that operators should determine pipeline 
specifications for all exposed facilities and use them to validate 
their records.
    8. Paiute and Southwest Gas reported that it is their practice to 
obtain pipeline data before an integrity management excavation and then 
to validate that information in the field.
    9. MidAmerican reported that it uses a geospatial database as its 
principal tool for collecting and validating pipeline information.
    10. An anonymous commenter suggested that pipeline operators do not 
routinely collect information to validate their databases during 
pipeline excavations.
Response to Question D.3 Comments
    PHMSA appreciates the information provided by the commenters. See 
response to question D.4.
    D.4. Should PHMSA make current requirements more prescriptive so 
operators will strengthen their collection and validation practices 
necessary to implement significantly improved data integration and risk 
assessment practices?
    1. INGAA, GPTC, Nicor, Ameren Illinois, MidAmerican, Paiute and 
Southwest Gas commented that additional prescriptive requirements are 
not needed. These commenters suggested that Advisory Bulletin ADB-11-
01, subpart O of part 192, and ASME/ANSI B31.8S are sufficient to 
govern these practices. INGAA added requirements for data validation 
during excavations could introduce workplace hazards that would 
outweigh any benefit to be gained. In the event PHMSA proceeds to 
propose new requirements, INGAA requested they be limited to a 
reasonable process and allow assumptions to be made to fill information 
gaps, suggesting this would be a more cost-effective approach than

[[Page 20762]]

rigorous requirements to collect and validate all information. A number 
of other pipeline operators provided comments supporting INGAA's 
comments.
    2. AGA, supported by a number of its pipeline operator members, 
commented that there is no evidence to support a need for more 
prescriptive requirements leading to better data collection or 
validation and, therefore, no such requirements are needed.
    3. Pipeline Safety Trust, NAPSR, California Public Utilities 
Commission, and Commissioners of Wyoming County, Pennsylvania, 
commented that requirements for data collection, validation, and use 
should be more prescriptive. These commenters noted that the 
investigation of the San Bruno accident identified at least one 
pipeline operator was not doing an adequate job of data validation. 
They noted that NTSB recommendations P-11-18 and P-11-19 apply to this 
topic. NAPSR specifically requested that new requirements specify 
precise inspection criteria.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
suggested that there is no value in periodic validation of pipeline 
data and new requirements are not needed in this area. Northern Natural 
Gas agreed, noting that pipeline data does not change over time, and 
relevant data that is subject to change, is that data needed to 
evaluate the consequences of potential pipeline accidents.
    5. Accufacts commented that more specific criteria, including 
minimum data requirements, are needed for record retention. Accufacts 
noted that integrity management is data-based and that too many 
operators claim that data is lost or cannot be found.
    6. Alaska Department of Natural Resources suggested that data 
integration should be required in interpreting ILI results.
    7. An anonymous commenter suggested that specific requirements are 
not needed in this area, contending that most data has been validated 
through normal operator practices.
    8. A private citizen suggested that PHMSA require pipeline 
operators to post all records for access by state and local government 
officials, PHMSA, and the media. The commenter suggested such a 
``sunshine'' provision would improve recordkeeping, even if no one ever 
examines the posted records.
Response to Question D.4 Comments
    PHMSA appreciates the information provided by the commenters in 
response to questions D.1 through D.4. Commenters disagreed on the need 
and benefit of making current requirements more prescriptive so 
operators will strengthen their collection and validation practices. 
PHMSA believes enhancing regulations in this area is an important 
element of good integrity management practices. On July 21, 2011, in 
response to the San Bruno incident, PHMSA sponsored a public workshop 
on risk assessment and related data analysis and recordkeeping issues 
to seek input from stakeholders. Based in part on the input received at 
this workshop, and the information submitted in response to the ANPRM, 
PHMSA proposes to clarify the performance-based requirements for 
collecting, validating, and integrating pipeline data by adding 
specificity to the data integration language, establishing a number of 
pipeline attributes that must be included in these analyses, explicitly 
requiring that operators integrate analyzed information, and ensuring 
data is reliable. The rule also requires operators to use validated, 
objective data to the maximum extent practical. PHMSA also understands 
that objective sources such as as--built drawings, alignment sheets, 
material specifications, and design, construction, inspection, testing, 
maintenance, manufacturer, or other related documents are not always 
available or obtainable. To the degree that subjective data from 
subject matter experts must be used, PHMSA proposes to require that an 
operator's program include specific features to compensate for subject 
matter expert bias. PHMSA believes that these proposed changes would 
not impose new requirements or more prescriptive requirements, but 
clarifies the intent of the regulation. However, PHMSA requests public 
comment on whether and the extent to which this proposal may change 
behavior.
    D.5. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.

    No comments were received in response to this question.

E. Making Requirements Related to the Nature and Application of Risk 
Models More Prescriptive

    The ANPRM requested comments regarding whether requirements related 
to the nature and application of risk models should be made more 
prescriptive to improve the usefulness of these analyses in controlling 
risks from pipelines. Current regulations require that gas transmission 
pipeline operators perform risk analyses of their pipelines and use 
these analyses to make certain decisions to assure the integrity of 
their pipeline and to enhance protection against the consequences of 
potential incidents. The regulations do not prescribe the type of risk 
analysis nor do they impose any requirements regarding its breadth and 
scope, other than requiring that it consider the entire pipeline. 
PHMSA's experience in inspecting operator compliance with IM 
requirements has identified that most pipeline operators use a relative 
index-model approach to performing their risk assessments and that 
there is a wide range in scope and quality of the resulting analyses. 
It is not clear that all of the observed risk analyses can support 
robust decision-making and management of the pipeline risk. The 
following are general comments received related to the topic as well as 
comments related to the specific questions:
General Comments for Topic E
    1. INGAA and Chevron commented that continuing the performance-
based regulatory approach, exemplified by integrity management, is 
critically important to pipeline safety. They suggested that 
prescriptive management systems are task oriented, do not adjust easily 
to new information or knowledge, inhibit innovation, and could thwart 
safety improvements. A number of other pipeline operators provided 
comments supporting INGAA's comments.
    2. Accufacts commented that risk management approaches permitted in 
IM need additional prescriptive measures to clarify strengths and 
weaknesses and to assure compliance. Public perception resulting from 
the number of serious incidents is that current risk analysis and risk 
management approaches are not sufficient. The impression is that risk 
management is being used to justify unwise lowest cost decisions rather 
than being used as a tool to avoid failure. Accufacts further suggested 
that interactive threats need to be addressed by prescriptive 
requirements in safety

[[Page 20763]]

regulations because operators may be under the illusion that some of 
the more serious threats are stable after almost 10 years of IM 
regulation.
    3. Oleksa and Associates suggested that it would be statistically 
more valid for many (perhaps most) operators for PHMSA to perform 
continual evaluation and assessment using established performance 
measures along with data submitted by operators on annual, incident, 
and safety-related condition reports, and then to promulgate more 
prescriptive regulations resulting from that assessment. Oleksa 
suggested that it may be time to re-evaluate the overall concept of 
integrity management to determine whether it makes sense for each 
operator to make assessments that might be more valid if made on a 
national level. Oleksa also stated that there should be a concerted 
effort in promulgating any new regulations towards making the 
regulations simple enough so that they can be understood relatively 
easily.
    4. TransCanada commented that PHMSA's IM regulations should provide 
explicit metrics for operators to demonstrate safety decision processes 
without restricting the opportunity to use more accurate and advanced 
methods. TransCanada said that any efforts to make risk models more 
prescriptive should focus on process elements while providing operators 
the flexibility to build processes which recognize the unique 
characteristics of their pipeline systems. The company also opined that 
issuing more detailed guidelines on specific integrity management plan 
elements would enhance the current, performance-based approach and 
generate additional benefits that the public and operators desire.
    5. Dominion East Ohio Gas opposed making requirements for risk 
models more prescriptive. Like INGAA, they that noted prescriptive 
management systems are task oriented and do not adjust easily to new 
information or knowledge. They inhibit innovation and could thwart 
safety improvements.
    6. NAPSR strongly urged PHMSA to make the nature and application of 
risk models more prescriptive. NAPSR commented that PHMSA has not 
provided any data that supports the theory that risk modeling provides 
a stronger safety environment and contended that, in fact, the opposite 
may be occurring.
    7. A private citizen suggested that PHMSA correlate the quality of 
an operator's risk model with the number of enforcement actions against 
that operator.
    8. A private citizen suggested that risk analysis requirements 
should remain flexible, commenting that prescribed methods or 
requirements could mask operator-specific issues.
Response to General Comments for Topic E
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that prescriptive rules for risk assessments are not appropriate 
because one-size-fits-all regulations would not be effective for such a 
diverse industry. However, PHMSA does believe that operator risk models 
and risk assessments should have substantially improved since the 
initial framework programs established nearly 10 years ago. While 
simple index or relative (qualitative) ranking models were useful to 
prioritize HCA segments for purposes of scheduling integrity baseline 
assessments, those models have limited utility to perform the analyses 
needed to better understand pipeline risks, better understand failure 
mechanisms (especially for interacting threats), or to identify 
effective preventive and mitigative measures. PHMSA is proposing to 
further clarify its expectations for this aspect of the performance-
based regulations to further improve pipeline safety. On July 21, 2011, 
PHMSA sponsored a public workshop on risk assessment to seek input from 
stakeholders. PHMSA has evaluated the input it received at this 
workshop. PHMSA proposes to clarify the risk assessment aspects of the 
IM rule to explicitly articulate functional requirements and to assure 
that risk assessments are adequate to: (1) Evaluate the effects of 
interacting threats, (2) determine intervals for continual integrity 
reassessments, (3) determine additional preventive and mitigative 
measures needed, (4) analyze how a potential failure could affect HCAs, 
including the consequences of the entire worst-case incident scenario 
from initial failure to incident termination, (5) identify the 
contribution to risk of each risk factor, or each unique combination of 
risk factors that interact or simultaneously contribute to risk at a 
common location, (6) account and compensate for uncertainties in the 
model and the data used in the risk assessment, and (7) evaluate 
predicted risk reduction associated with preventive and mitigative 
measures. In addition, in response to NTSB recommendation P-11-18, 
PHMSA proposes to require that operators validate their risk models in 
light of incident, leak, and failure history and other historical 
information. PHMSA also proposes to expand the list of example 
preventive and mitigative measures to include the following items: 
establish and implement adequate operations and maintenance processes 
that could affect safety; establish and deploy adequate resources for 
successful execution of activities, processes, and systems associated 
with operations, maintenance, preventive measures, mitigative measures, 
and managing pipeline integrity; and correct the root cause of past 
incidents to prevent recurrence.
    In response to Oleksa's comments, PHMSA is addressing performance 
measures outside of this rulemaking. Performance measures will be 
addressed separately in response to NTSB safety recommendations P-11-18 
and P-11-19.
Comments Submitted for Questions in Topic E
    E.1. Should PHMSA either strengthen requirements on the functions 
risk models must perform or mandate use of a particular risk model for 
pipeline risk analyses? If so, how and which model?
    1. INGAA, AGA, and many pipeline operators reported that they do 
not believe there is a pipeline safety benefit for PHMSA to 
``strengthen'' or revise the requirements on functions that risk models 
must perform or in mandating the use of specific risk models. These 
commenters noted that there is a tremendous amount of diversity in the 
pipeline systems of individual operators and operators must have the 
flexibility to select the risk model that best supports their systems.
    2. GPTC commented that there is no `one-size-fits-all' risk model. 
GPTC further commented PHMSA has offered no data supporting the need to 
strengthen requirements or mandate a particular risk model.
    3. Kern River noted that differences exist between pipeline 
operators on how much detail is needed in their risk assessment models. 
The specific factors and required risk model complexity will differ for 
each pipeline company based on its active threats, the preventive and 
mitigative measures employed, its data acquisition methods and the 
amount of required data.
    4. MidAmerican commented that no change is needed to requirements 
concerning risk models. MidAmerican noted that ASME/ANSI B31.8S 
provides extremely detailed requirements in this area, and suggested 
that operators should have the freedom to choose the risk model best 
suited to their operation. Northern Natural Gas agreed, noting that 
there are large differences within the industry on the complexity of 
the risk assessment models used based on the

[[Page 20764]]

pipeline age and configuration, threats, and data available.
    5. Paiute and Southwest Gas opposed more restrictive requirements 
for risk modeling. They noted that operators have a decade of 
experience working with IM and therefore, should have the flexibility 
to choose the risk model that best suits their system.
    6. Accufacts commented that this is an area that needs more 
prescriptive requirements. Accufacts questioned whether the current 
approach of reliance on risk modeling is even appropriate. They stated 
that there appears to be a disconnect between the use of risk models 
and risk analysis with pipeline operation and the ability of regulators 
to apply and enforce the approach.
    7. TransCanada noted that mandating the use of a specific risk 
model may result in a more uniform approach across the industry, but 
may also force operators to abandon their existing risk models, 
including the improvements made to them based on 10 years of integrity 
management experience. This would not appear to advance risk modeling 
and might even be counterproductive.
    8. WKM Consultancy commented that mandating a specific risk 
assessment model would not be a beneficial addition to regulations. 
Such a mandate would stifle creativity and require extensive 
definitions and documentation of that methodology. A mandated model 
would introduce a prescriptive element with substantial ``overhead'' 
related to the maintenance of the model's documentation by the 
regulators. They suggested that a better solution would be to develop 
guidelines of essential ingredients necessary in any pipeline risk 
assessment.
    9. An anonymous commenter opposed requiring the use of a specific 
risk model, suggesting that operators should use models with which they 
are comfortable. The commenter did suggest that PHMSA strengthen 
requirements concerning the use of risk models for purposes other than 
risk-ranking segments, expressing a belief that most operators are 
using their models only for that purpose.
    10. California Public Utilities Commission recommended that PHMSA 
require statistical data be maintained and used to support the 
weightings assigned by risk models to various threats.
Response to Question E.1 Comments
    PHMSA appreciates the information provided by the commenters. A 
large number of comments do not support adding a requirement for a 
specific risk assessment model or for strengthening or revising the 
required functions that risk models must perform. PHMSA agrees that 
prescribing the use of particular risk assessment models is not 
appropriate for such a diverse industry, and notes that relative index 
models have been successfully used to rank pipelines to prioritize 
baseline assessments. However, PHMSA believes that the integrity 
management rule anticipates that operators would continually improve 
their risk assessment processes and that there are specific risk 
assessment attributes related to the nature and application of risk 
models that need clarification. Such attributes and shortcomings were 
discussed at the ``Improving Pipeline Risk Assessments and 
Recordkeeping'' workshop with stakeholders, held on July 21, 2011.
    PHMSA proposes to articulate clear functional requirements, in 
performance-based terms, for risk assessment methods used by operators. 
While PHMSA does not propose to prescribe the specific risk assessment 
model operators must use, PHMSA does propose to clarify the 
characteristics of a mature risk assessment program. These include: (1) 
Identifying risk drivers; (2) evaluating interactive threats; (3) 
assuring the use of traceable and verifiable information and data; (4) 
accounting for uncertainties in the risk model and the data used; (5) 
incorporating a root cause analysis of past incidents; (6) validating 
the risk model in light of incident, leak and failure history and other 
historical information; (7) using the risk assessment to establish 
criteria for acceptable risk levels; and (8) determining what 
additional preventive and mitigative measures are needed to achieve 
risk reduction goals. PHMSA proposes to clarify that the risk 
assessment method selected by the operator must be capable of 
successfully performing these functions.
    E.2. It is PHMSA's understanding that existing risk models used by 
pipeline operators generally evaluate the relative risk of different 
segments of the operator's pipeline. PHMSA is seeking comment on 
whether or not that is an accurate understanding. Are relative index 
models sufficiently robust to support the decisions now required by the 
regulation (e.g., evaluation of candidate preventive and mitigative 
measures, and evaluation of interacting threats)?
    1. Industry commenters, including INGAA, AGA, Texas Pipeline 
Association, Texas Oil & Gas Association, WKM Consultancy, and many 
pipeline operators reported that PHMSA's understanding is correct and 
that risk models in use generally evaluate the relative risk of 
different segments of the operator's pipeline. AGA noted that operators 
have selected and implemented the risk models that allowed them to 
prioritize the covered segments for the baseline assessment and 
subsequent reassessments and that this complied with the Pipeline 
Safety Improvement Act of 2002.
    2. AGA, supported by a number of its pipeline operator members, 
commented that risk models currently in use are sufficiently robust. 
Ameren Illinois and GPTC expressed a similar belief.
    3. INGAA, supported by some of its members, noted that there is 
room for improvement in the current practices of risk modeling. INGAA 
reported that the industry has established committees to identify 
advancements in risk modeling.
    4. WKM Consultancy commented that the more robust of the relative 
risk index techniques are often capable of fulfilling some aspects of 
IM risk management requirements such as prioritization, but that other 
aspects of the risk management requirements are not well supported by 
relative risk assessments. They suggested that some risk assessment 
models in current use could benefit from application of more robust and 
modern techniques.
    5. Kern River commented that a relative risk model is sufficiently 
robust to support decisions on preventive and mitigative measures and 
assessment intervals.
    6. MidAmerican reported that its risk model complies with ASME/ANSI 
B31.8S and is sufficiently robust to support decisions that are not 
specifically related to assessments. MidAmerican further stated that 
its risk model produces results consistent with its subject matter 
expert assessments of relative risk.
    7. Paiute and Southwest Gas reported their conclusion that their 
risk models are robust and support the process of evaluation and 
selection of preventive and mitigative measures.
    8. Texas Pipeline Association and Texas Oil & Gas Association noted 
that all sources of information relative to the integrity of a 
transmission pipeline segment and the identified risk should be used in 
the selection of preventive and mitigative measures. Atmos agreed, 
noting that preventive and mitigative measures for a given pipeline 
segment are based on the identified threats.
    9. A private citizen suggested that consideration of system-wide 
high risk (e.g., urban areas) should be required, contending relative 
risk is not good enough when an entire system poses high risks.

[[Page 20765]]

Response to Question E.2 Comments
    PHMSA appreciates the information provided by the commenters. 
Although a large number of comments contend risk models currently in 
use are sufficiently robust, PHMSA believes that there are specific 
risk assessment attributes not found in many of the simple index or 
relative risk models currently in use. The July 21, 2011, workshop on 
``Improving Pipeline Risk Assessments and Recordkeeping'' identified 
several shortcomings in risk assessments conducted using qualitative, 
index, or relative risk methodologies, and PHMSA is proposing to 
clarify requirements to address these issues including the need for 
better or more prescriptive guidance to address data gaps, data 
integration, uncertainty, interacting threats, risk management, and 
quantitative approaches instead of subjective or qualitative 
approaches. The proposed regulation would require operators to conduct 
risk assessments that effectively analyze the identified threats and 
potential consequences of an incident for each HCA segment. 
Additionally, the proposed regulation would require the risk assessment 
to include evaluation of the effects of interacting threats, including 
those threats and anomalous conditions not previously evaluated. It 
should be further noted that the intent of the original IM rule is that 
any risk assessment would consider system-wide risk.
    E.3. How, if at all, are existing models used to inform executive 
management of existing risks?
    1. INGAA commented that operators should develop internal 
communication plans and they should follow Section 10.3 of ASME/ANSI 
B31.8S in doing so. AGA similarly noted that the methods used to 
disseminate results of the risk evaluation to executive management are 
operator specific and detailed in the operator's integrity management 
plan. A number of pipeline operators provided comments supporting both 
INGAA's and AGA's comments.
    2. Texas Pipeline Association and Texas Oil & Gas Association noted 
that the results of risk modeling are usually used in conjunction with 
assessment results to inform executive management of actions required 
beyond normal repair, additional preventive and mitigative measures, 
discussion of high risk pipelines, and progress in meeting assessment 
goals.
    3. WKM Consultancy commented that operators are obliged to 
communicate all aspects of integrity management to higher level 
managers at regular intervals. They noted that all prudent operators 
are very interested in risk management and results of risk modeling are 
usually a centerpiece of discussion and decision-making.
    4. Ameren Illinois reported that its IM plan provides for informing 
executive management of existing risks.
    5. Atmos reported that it provides executive management with 
periodic updates on the status of its integrity management program. 
During these updates, Atmos' executive management reviews baseline 
assessment plans, assessment results, anomalies discovered and 
mitigated, anomalies discovered and scheduled for repair, leading 
causes of anomalies, and preventive and mitigative actions taken.
    6. Kern River noted that it provides its executive management with 
reports describing integrity management program activities and results 
and that the company engages the use of the risk model as an input to 
financial planning and maintenance planning. MidAmerican also reported 
that risk scores are used to support capital, operating and maintenance 
expenditures to executive management.
    7. Northern Natural Gas reported that it provides executive 
management with reports describing integrity management program 
activities and results. Its executive management is engaged in the 
process and the use of the risk model to prioritize projects.
    8. Paiute and Southwest Gas reported that integrity management 
activities are discussed with executive management quarterly.
    9. An anonymous commenter suggested that operators generally do not 
use risk models to inform executives, because they would have to 
explain the models in order to do so.
Response to Question E.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
understands that internal company processes for communication with 
executive management are specific to each company. To strengthen the 
application of risk assessment, PHMSA is proposing to clarify 
requirements by providing more specific and detailed examples of the 
kinds of preventive and mitigative measures operators should consider. 
The proposed rulemaking would include the following specific examples 
of preventive and mitigative measures that operators should consider: 
Establish and implement adequate operations and maintenance processes; 
establish and deploy adequate resources for successful execution of 
activities, processes, and systems associated with operations, 
maintenance, preventive measures, mitigative measures, and managing 
pipeline integrity; and correct the root cause of past incidents to 
prevent recurrence. The last item necessarily requires a robust root 
cause analysis that identifies underlying programmatic or policy issues 
that create or facilitate conditions or circumstances that ultimately 
lead to pipeline failures.
    E.4. Can existing risk models be used to understand major 
contributors to segment risk and support decisions regarding how to 
manage these contributors? If so, how?
    1. INGAA and many of its pipeline operator members commented that 
existing models can and do provide an understanding of segment risk 
through threat identification, performing ``what if'' analyses, and 
identifying preventive and mitigative measures that will reduce risk.
    2. AGA and GPTC noted that existing models selected by operators 
are sufficiently robust to allow the integration of large volumes of 
data and information to achieve a comprehensive overall risk evaluation 
for their systems. These risk models allow an operator to understand 
the specific threats associated with each pipeline segment and the 
preventive and mitigative measures that would be most appropriate. A 
number of pipeline operators provided comments supporting AGA's 
comments.
    3. WKM Consultancy opined that currently used risk assessment 
models generally can significantly improve the ability to manage risks. 
They noted that a formal risk assessment provides the structure to 
increase understanding, reduce subjectivity, and ensure that important 
considerations are not overlooked.
    4. Atmos reported that its model can be used to generate a report 
listing the significant variables contributing to a relatively higher 
risk factor score, and that if a contributing variable can be 
controlled, the risk model can support further actions to control the 
variable.
    5. Ameren Illinois reported that it uses a robust risk model that 
can integrate various risk factors in order to evaluate its system.
    6. Kern River and Northern Natural Gas commented that existing risk 
models can be used to understand major contributors to segment risk and 
support decisions regarding how to manage these contributors. By 
identifying threat drivers in the risk results and analyzing the data 
used by the model, integrity management personnel are able to reduce 
risk through preventive and mitigative measures, improvements in data 
quality, and shorter reassessment intervals.

[[Page 20766]]

    7. MidAmerican reported that its risk model is used to understand 
major contributors to risk and to support decisions regarding how to 
manage those contributors.
    8. Paiute and Southwest Gas reported that they conduct a review of 
threat-specific indices to identify the major contributors to risk for 
each threat.
    9. Texas Pipeline Association and Texas Oil & Gas Association noted 
that risk modeling can be used to generate reports listing the 
significant variables contributing to high risk scores.
    10. An anonymous commenter noted that risk models can serve these 
functions and some operators use them in this way. The commenter opined 
that most operators ``aren't there yet,'' and that operators who use 
models for this purpose have more enthusiasm for integrity management 
and more executive management support.
Response to Question E.4 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of the comments suggest that current risk models provide an 
adequate understanding of major contributors to risk. PHMSA believes it 
is prudent to clarify the required attributes of risk assessment in 
this area and proposes to include performance-based language to assure 
that risk assessments adequately identify the contribution to risk of 
each risk factor, or each unique combination of risk factors that 
interact or simultaneously contribute to risk at a common location.
    E.5. How can risk models currently used by pipeline operators be 
improved to assure usefulness for these purposes?
    1. INGAA noted that continuous improvement is required, and that 
industry is working on improvements to ASME/ANSI B31.8S. AGA similarly 
noted that risk models are periodically improved by operators by 
integrating new data and the results of integrity assessments. A number 
of pipeline operators provided comments supporting INGAA's and AGA's 
comments.
    2. GPTC commented that new data and information are received on an 
ongoing basis. This new data, and results of integrity assessments, are 
reviewed, integrated, and added to risk models periodically.
    3. WKM Consultancy suggested that a limited amount of 
standardization would be appropriate. They opined that this would 
ensure that all risk assessments contain, at a minimum, a short list of 
essential ingredients. For example, all assessments should produce a 
profile showing changes in risk along a pipeline route.
    4. Ameren Illinois reported that its risk model allows for 
integration of information for continuous improvement.
    5. Atmos commented that there is the potential for the risk model 
process to handle unknown data in a more useful manner. Atmos suggested 
that a higher risk score with ``known'' data attributes should be 
considered more relevant for decisions on preventive and mitigative 
measures than a similar score derived from ``unknown'' data attributes.
    6. Kern River suggested that industry-wide research into failure 
probabilities and effectiveness of preventive and mitigative measures 
would facilitate more rigorous quantitative models. Kern River noted 
that vendors are continuously improving risk models.
    7. MidAmerican suggested that risk models could be improved with 
better tracking, recording, and retrieval of assessment results. With 
feedback and information sharing, refining coefficients within the 
model will produce more accurate risk results.
    8. Northern Natural Gas reported that its risk assessment process 
is improved every year and that its risk model vendor is heavily 
involved with the company in understanding how the risk results are 
used.
    9. Paiute and Southwest Gas suggested that risk models will be 
improved as additional information is gained through an assessment 
cycle and that this continuous improvement process will then repeat 
through subsequent assessment cycles.
    10. Texas Pipeline Association and Texas Oil & Gas Association 
observed that there is no `one size fits all' solution to this issue.
Response to Question E.5 Comments
    PHMSA appreciates the information provided by the commenters. The 
comments speak in general terms about incremental improvement of 
existing index-type or qualitative relative risk models. PHMSA believes 
that such models, while appropriate and useful for limited purposes 
such as ranking segments to prioritize baseline assessments, fall far 
short of the type of model needed to fully execute a mature integrity 
management program. PHMSA proposes to clearly articulate the 
requirements for validation of the risk assessment and proposes to 
clarify that an operator must ensure validity of the methods used to 
conduct the risk assessment in light of incident, leak, and failure 
history and other historical information. Additionally, the proposed 
rule would require that validation must: (1) Ensure the risk assessment 
methods produce a risk characterization that is consistent with the 
operator's and industry experience, including evaluations of the cause 
of past incidents as determined by root cause analysis or other means; 
and (2) include analysis of the factors used to characterize both the 
probability of loss of pipeline integrity and consequences of the 
postulated loss of pipeline integrity.
    E.6. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.

    No comments were received in response to this question.

F. Strengthening Requirements for Applying Knowledge Gained Through the 
IM Program

    The ANPRM requested comments regarding strengthening requirements 
related to operators' use of insights gained from implementation of an 
IM program. IM assessments provide information about the condition of 
the pipeline. Identified anomalies that exceed criteria in Sec.  
192.933 must be remediated immediately (Sec.  192.933(d)(1)) or within 
one year (Sec.  192.933(d)(2)) or must be monitored on future 
assessments (Sec.  192.933(d)(3)). Operators are also expected to apply 
knowledge gained through these assessments to assure the integrity of 
their entire pipeline as part of its threat identification and risk 
analysis process in accordance with Sec.  192.917.
    Section 192.917(e)(5) explicitly requires that operators must 
evaluate other portions of their pipeline if an assessment identifies 
corrosion requiring repair under the criteria of Sec.  192.933. The 
operator must ``evaluate and remediate, as necessary, all pipeline 
segments (both covered and non-covered) with similar material coating 
and environmental characteristics.''
    Section 192.917 also requires that operators conduct risk 
assessments that follow American Society of Mechanical Engineers/
American National Standards Institute (ASME/ANSI) B31.8S, Section

[[Page 20767]]

5, and use these analyses to prioritize segments for assessment, and to 
determine what preventive and mitigative measures are needed for 
segments in HCAs. Section 5.4 of ASME/ANSI B31.8S states that ``risk 
assessment methods should be used in conjunction with knowledgeable, 
experienced personnel . . . that regularly review the data input, 
assumptions, and results of the risk assessments.'' That section 
further states, ``an integral part of the risk assessment process is 
the incorporation of additional data elements or changes to facility 
data,'' and requires that operators ``incorporate the risk assessment 
process into existing field reporting, engineering, and facility 
mapping processes'' to facilitate such updates. Neither part 192 nor 
ASME/ANSI B31.8S specifies a frequency at which pipeline risk analyses 
must be reviewed and updated; instead, this is considered to be a 
continuous, ongoing process. The following are general comments 
received related to the topic as well as comments related to the 
specific questions:
General Comment for Topic F
    1. MidAmerican suggested that application of knowledge gained 
through integrity management should not be treated any differently than 
any other information gained from work on or surveillance of the 
pipeline. MidAmerican considers this to be adequately addressed by 
Sec.  192.613.
Response
    PHMSA continues to believe that there are many important integrity 
management requirements related to insights gained from implementation 
of the IM program beyond those covered by the continuing surveillance 
requirements of Sec.  192.613. Integrity management assessments provide 
information about the condition of the pipeline and operators are 
expected to apply the knowledge gained through these assessments to 
assure the integrity of their entire pipeline. PHMSA believes that the 
knowledge gained through IM assessments should be integrated into the 
risk assessment process, which is not required by Sec.  192.613.
Comments Submitted for Questions in Topic F
    F.1. What practices do operators use to comply with Sec.  
192.917(e)(5)?
    1. INGAA and a number of pipeline operators noted that operators 
use available information and field knowledge to comply with this 
requirement.
    2. AGA, supported by a number of its member companies, reported 
that operator practices are too distinct and varied to list. AGA stated 
that Sec.  192.917(e)(5) is prescriptive enough and no new requirements 
are needed.
    3. GPTC and Nicor cited NACE SP0169 and NACE RP0177 as examples of 
standards that can be used to guide compliance with Sec.  
192.917(e)(5).
    4. Texas Pipeline Association and Texas Oil & Gas Association 
commented that operators use cathodic protection surveys and/or spot 
checks to determine whether failure is likely.
    5. Northern Natural Gas reported that it takes the actions 
specified in Sec.  192.917(e)(5) and includes consideration of 
incidents and safety related conditions.
    6. Kern River, Paiute, and Southwest Gas stated that they use root 
cause evaluations of incidents to comply with Sec.  192.917(e)(5).
Response to Question F.1 Comments
    PHMSA appreciates the information provided by the commenters. The 
comments provide little information related to specific operator 
practices for compliance with Sec.  192.917(e)(5). PHMSA is not 
proposing to amend Sec.  192.917(e)(5) at this time; however, PHMSA 
proposes to clarify requirements in Sec.  192.917(b) to ensure that the 
data gathering and integration process includes an analysis of both the 
HCA segments and similar non-HCA segments and integrates information 
about pipeline attributes and other relevant information, including 
data gathered through integrity assessments.
    F.2. How many times has a review of other portions of a pipeline in 
accordance with Sec.  192.917(e)(5) resulted in investigation and/or 
repair of pipeline segments other than the location on which corrosion 
requiring repair was initially identified?
    1. Based on a limited response by their members to a survey, Texas 
Pipeline Association and Texas Oil & Gas Association reported that 
repair of corrosion beyond the initially-identified anomaly is rare.
    2. Ameren Illinois reported that it has experienced two instances 
in which it repaired other segments after identifying corrosion on a 
covered pipeline segment.
    3. MidAmerican reported that it has experienced a few instances of 
corrosion where coating was damaged during installation of a vent, and 
some at air-to-soil interfaces.
    4. Northern Natural Gas has experienced no instances in which other 
pipeline segments required repair. Northern added that corrosion wall 
loss requiring repair is, itself, rare.
    5. Paiute and Southwest Gas reported that they had not identified 
any immediate repair corrosion conditions.

Response to Question F.2 Comments

    PHMSA appreciates the information provided by the commenters. See 
the response to question F.1.
    F.3. Do pipeline operators assure that their risk assessments are 
updated as additional knowledge is gained, including results of IM 
assessments? If so, how? How is data integration used and how often is 
it updated? Is data integration used on alignment maps and layered in 
such a way that technical reviews can identify integrity-related 
problems and threat interactions? How often should aerial photography 
and patrol information be updated for IM assessments? If the commenter 
proposes a time period for updating, what is the basis for this 
recommendation?
    1. INGAA and several pipeline operators reported that operators 
update risk analyses whenever new information is obtained and 
particularly after unexpected events.
    2. AGA, GPTC, Nicor, Kern River, and TransCanada commented that 
risk analyses are updated at least annually.
    3. Northern Natural Gas reported that its procedures provide for 
updating to include assessment results and changes in environmental 
factors.
    4. Paiute and Southwest Gas reported that risk model updating is a 
continuous process. Rankings are updated at 18- to 24-month intervals. 
Ameren Illinois and Atmos similarly reported that updating is an 
ongoing activity.
    5. Texas Pipeline Association and Texas Oil & Gas Association 
commented that most operators have dedicated teams to perform risk 
model updates.
    6. Alaska Department of Natural Resources commented that risk 
models should be reviewed whenever significant operational or 
environmental changes occur. AKDNR contended that risk models are not 
valid if there are significant changes in these areas.
    7. NAPSR reported its conclusion that risk models should be updated 
after every O&M activity or any finding that a required activity was 
not performed.
    8. INGAA and a number of pipeline operators reported that data is 
updated using a common spatial reference system, e.g., maps or tables, 
and the frequency of data integration varies by operator.
    9. AGA, supported by a number of its member companies, reported 
that data integration does not always involve use of geospatial tools.

[[Page 20768]]

    10. Atmos reported that it uses internal teams of subject matter 
experts for data integration and that its maps are not layered for 
technical data use.
    11. Northern Natural Gas, Paiute, and Southwest Gas stated that 
they perform integration on alignment sheets based on integrity 
management summaries and subject matter expert reviews.
    12. Texas Pipeline Association and Texas Oil & Gas Association 
reported that many pipeline operators are migrating to GIS systems.
    13. INGAA and many pipeline operators commented that information 
from aerial photography should be updated annually. They noted that 
this would be consistent with the frequency of reviewing HCA 
designations and operator budgeting and contended that more frequent 
updates would not increase risk model accuracy. INGAA suggested that 
other information, including information related to external events, 
should be updated based on the nature and severity of experienced 
events.
    14. AGA, Paiute, and Southwest Gas noted that not all operators use 
aerial photography and expressed their belief that such use should not 
be required. AGA noted that there are many tools, including routine 
patrols, to gather data about the pipeline environment. A number of 
member pipeline operators supported AGA's comments.
    15. Northern Natural Gas reported that it updates information 
periodically, but with no set frequency. Northern noted that some areas 
are stable while change can occur rapidly in others.
    16. Texas Pipeline Association and Texas Oil & Gas Association 
recommended annual updates as a minimum. The associations noted that 
this recognizes the time required to produce/acquire assessment data.
Response to Question F.3 Comments
    PHMSA appreciates the information provided by the commenters. After 
review of the comments, PHMSA agrees that annual updates are desirable 
and many operators perform full updates, or partial data updates (such 
as updating aerial photos), annually. Some pipeline segments may be in 
rapidly changing, dynamic environments, while others may remain static 
for years. PHMSA also agrees that prescriptive requirements to perform 
a full risk assessment annually are not necessary and potentially 
burdensome, especially for very small operators, whose systems and 
conditions do not change often. PHMSA is satisfied that the current 
requirement, which contains a performance based requirement to update 
risk assessments as frequently as needed to assure the integrity of 
each HCA segment is adequate, if properly implemented, and is not 
proposing a prescribed frequency at this time. However, PHMSA proposes 
to clarify requirements in Sec. Sec.  192.917 and 192.937(b) to ensure 
the continual process of evaluation and assessment is based on an 
updated and effective data integration and risk assessment process as 
specified in Sec.  192.917.
    F.4. Should the regulations specify a maximum period in which 
pipeline risk assessments must be reviewed and validated as current and 
accurate? If so, why?
    1. INGAA and numerous pipeline operators recommended that reviews 
be annual, as suggested in PHMSA's Gas Integrity Management Program 
Frequently Asked Question FAQ-234, arguing that this is practical and 
sufficient (FAQs can be viewed at http://primis.phmsa.dot.gov/gasimp/faqs.htm).
    2. AGA, GPTC, and a number of other pipeline operators commented 
that no maximum period should be specified for review of risk 
assessments. These commenters argued that no one-size-fits-all interval 
would be appropriate and expressed their conclusion that the current 
requirements in Sec.  192.937 are adequate.
    3. California Public Utilities Commission recommended that reviews 
be required annually, at intervals not to exceed 15 months, consistent 
with other requirements within part 192.
    4. An anonymous commenter suggested that a specified review period 
would be counterproductive, arguing that most operators would simply 
default to the required interval, even if more frequent reviews were 
appropriate.
Response to Question F.4 Comments
    PHMSA appreciates the information provided by the commenters. See 
PHMSA response to comments related to Question F.3.
    F.5. Are there any additional requirements PHMSA should consider to 
assure that knowledge gained through IM programs is appropriately 
applied to improve safety of pipeline systems?
    1. INGAA and many pipeline operators opined that no new 
requirements are needed in this area. They noted that prescriptive 
requirements often become out of date as technology improves.
    2. AGA and numerous pipeline operators agreed that no new 
requirements are needed, noting that existing regulations and sharing 
of information through industry groups is sufficient.
    3. Texas Pipeline Association and Texas Oil & Gas Association 
opined that existing requirements are adequate.
    4. Accufacts suggested that requirements should be more 
prescriptive concerning threat evaluation and interactive threats, as 
this is the heart of integrity management.
    5. An anonymous commenter suggested that new requirements be 
established governing assessments conducted by pressure testing. The 
commenter opined that the requirements in subpart J are inadequate and 
represent an ``easy out'' for some operators.
Response to Question F.5 Comments
    PHMSA appreciates the information provided by the commenters. While 
PHMSA believes that explicit requirements should be included to address 
interactive threats, PHMSA also believes that prescriptive rules for 
how an operator must evaluate interactive threats are not practical. 
Therefore, PHMSA proposes to clarify performance-based requirements to 
include an evaluation of the effects of interacting threats and for the 
continual process of evaluation and assessment to include interacting 
threats in identification of threats specific to each HCA segment. 
Comments on integrity assessment methods are addressed in Topic G.
    F.6. What do operators require for data integration to improve the 
safety of pipeline systems in HCAs? What is needed for data integration 
into pipeline knowledge databases? Do operators include a robust 
database that includes: Pipe diameter, wall thickness, grade, and seam 
type; pipe coating; girth weld coating; maximum operating pressure 
(MOP); HCAs; hydrostatic test pressure including any known test 
failures; casings; any in-service ruptures or leaks; ILI surveys 
including high resolution--magnetic flux leakage (HR-MFL), HR geometry/
caliper tools; close interval surveys; depth of cover surveys; 
rectifier readings; test point survey readings; alternating current/
direct current (AC/DC) interference surveys; pipe coating surveys; pipe 
coating and anomaly evaluations from pipe excavations; SCC excavations 
and findings; and pipe exposures from encroachments?
    1. INGAA, supported by a number of pipeline operators, commented 
that experience and information gained from a variety of sources, 
including GIS data, corrosion data, ILI data/results, work management 
activities, SCADA, encroachments, leaks etc., is utilized in data 
integration. INGAA reported that operators have made major investments

[[Page 20769]]

in database applications to meet changing organizational and regulatory 
requirements and to manage increasing volumes of data effectively. 
Tools generally are available for integrating data into pipeline 
knowledge databases. For integration purposes, the database must 
contain adequate metadata elements such that dates, if important, and 
location and length attributes are maintained. Currently-available 
systems support these needs. INGAA expressed concern over use of the 
term ``robust database,'' since this could be construed to mean that 
all applicable data must be maintained in a common database or other 
venue which does not meet the particular needs of the operator. INGAA 
reported that it has an active Integrity Management--Continuous 
Improvement (IMCI) team addressing improvement in these processes and 
management systems.
    2. AGA, GPTC, and a number of pipeline operators commented that a 
prescriptive requirement would be inappropriate because there is too 
much variability among operators and their risk assessment methods. AGA 
expressed its conclusion that there is no single methodology that 
incorporates the wide variety of pipeline information used by 
operators.
    3. MidAmerican suggested that an operator needs a robust computer 
model to integrate diverse data dynamically into one table with one set 
stationing.
    4. Kern River reported that it uses extensive GIS and cathodic 
protection databases for these purposes.
    5. An anonymous commenter recommended that PHMSA require knowledge 
of cathodic protection current level, amount, and direction of current 
flow. The commenter opined that this information is not now generally 
collected, and that it would allow for early detection of coating 
failures and CP interferences.
Response to Question F.6 Comments
    PHMSA appreciates the information provided by the commenters. An 
integral part of applying information from the IM Program to the risk 
assessment and other analyses is the collection, validation, and 
integration of pipeline data. PHMSA proposes to clarify the data 
integration language in the requirements by repealing the reference to 
ASME/ANSI B31.8S and including requirements associated with data 
integration directly in the rule text: (1) Establishing a number of 
pipeline attributes that must be included in these analyses, (2) 
clarifying that operators must integrate analyzed information, and (3) 
ensuring that data are verified and validated.
    F.7. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

G. Strengthening Requirements on the Selection and Use of Assessment 
Methods

    The existing IM regulations require that baseline and periodic 
assessments of pipeline segments in an HCA be performed using one of 
four methods:
    (1) In-line inspection;
    (2) Pressure test in accordance with subpart J;
    (3) Direct assessment to address the threats of external and 
internal corrosion and SCC; or
    (4) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of line pipe.
    Operators must notify PHMSA in advance if they plan to use ``other 
technology.'' Operators must apply one or more methods, depending on 
the threats to which the HCA segment is susceptible. The ANPRM 
requested comments related to the applicability, selection, and use of 
each assessment method, existing consensus standards and requirements, 
and the potential need to strengthen the requirements. The ANPRM then 
listed questions for consideration and comment. The following are 
general comments received related to the topic as well as comments 
related to the specific questions:
General Comments for Topic G
    1. INGAA, supported by a number of its pipeline operator members, 
noted that they are committed to work with technology providers and 
researchers to improve the integrity management assessment capabilities 
of its members. Further, INGAA members are sharing their experiences 
with applying these new and improved assessment methods to specific 
threats. INGAA opined that a great advantage of the integrity 
management structure, as opposed to a prescriptive regulatory regime, 
is the creation of an environment conducive to technological 
development, innovation and improved knowledge.
    2. Accufacts suggested that a more prescriptive regulation is 
needed clarifying the applicability and limitations of direct 
assessment. Accufacts is concerned that operators are selecting direct 
assessment due to a cost bias while ignoring that it cannot be used for 
all threats and should not be used on some pipeline segments.
    3. Chevron commented that PHMSA should continue to allow operators 
to select and use the most effective method to assess each pipeline 
segment.
    4. NAPSR recommended that PHMSA implement a regulatory change that 
requires both ILI and pressure testing for all transmission pipelines 
and requires a reduction in MAOP until either the ILI or the pressure 
tests are performed.
    5. MidAmerican, a gas distribution company, noted that many of its 
transmission pipelines are short, small diameter lines that cannot be 
pigged.
    6. Dominion East Ohio suggested that PHMSA should be funding more 
research leading to the development of assessment tools, particularly 
smart tools, to increase the number of assessment options available 
rather than limiting the tools that can be used.
    7. A public citizen commented that pipe with unknown or uncertain 
specifications should be subject to the most stringent testing 
requirements.
    8. Two public citizens addressed required assessment intervals. One 
suggested that all pipe that puts the public at significant risk should 
be tested, by hydro testing or some other means, at approximately ten-
year intervals. Another commenter recommended that assessments be 
required more frequently in densely populated areas.
    9. PST opined that the need to ask the questions in this section 
makes clear that PHMSA's current level of oversight and review of IM 
planning and implementation is inadequate, and calls into question the 
value of many IM programs, particularly those relying to any extent on 
direct assessment methods. PST recommended that the regulations be 
significantly strengthened to require PHMSA's review and administration 
approval of any IM program.
Response
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that pipeline operators should be able to select the best 
assessment

[[Page 20770]]

method applicable for its pipelines and circumstances. PHMSA also 
agrees with NAPSR and other commenters that additional requirements are 
needed for assessing more miles of pipeline that pose a risk to the 
public. PHMSA has also identified the need to address specific issues 
related to the selection of integrity assessment methods that have been 
identified following the San Bruno incident, especially related to the 
use of direct assessment. Therefore, PHMSA proposes to add more 
specific requirements related to (1) performance of integrity 
assessments for pipe not covered by subpart O (i.e., pipeline not 
located in a high consequence area) that represents risk to the public, 
and (2) selection of assessment methods. Specifically, PHMSA proposes 
to revise the requirements in Sec. Sec.  192.921 and 192.937 as 
follows: (1) Allow direct assessment only if a line is not capable of 
inspection by internal inspection tools; (2) add a newly defined 
assessment method: ``spike'' hydrostatic test; (3) add excavation and 
in situ direct examination as an allowed assessment method; and (4) add 
guided wave ultrasonic testing (GWUT) as an allowed assessment method. 
In addition, PHMSA proposes to add a new Sec.  192.710 to require that 
a significant portion of pipelines not covered by subpart O be 
periodically assessed using integrity assessment techniques similar to 
those proposed for HCA segments. Specifically, PHMSA proposes to 
require that all pipeline segments in class 3 and class 4 locations and 
moderate consequence area as defined in Sec.  192.3 if the pipe segment 
can accommodate inspection by means of instrumented inline inspection 
tools (i.e., ``smart pigs''), be periodically assessed. Although PHMSA 
proposes to provide selected, more prescriptive requirements for the 
selection of assessment methods, the pipeline safety regulations would 
continue to allow the use of other technology that an operator 
demonstrates can provide an equivalent understanding of the condition 
of the line pipe (comparable to a specified integrity assessment such 
as pressure testing or inline inspection), in order to continue to 
encourage research and development of more effective assessment 
technologies similar to the successful development of GWUT. For non-HCA 
segments, operator notification to PHMSA of the selection of other 
technologies would not be required.
    PHMSA understands the Pipeline Safety Trust's recommendation that 
the regulations require PHMSA's review and approval of any IM program. 
PHMSA believes its current approach to inspection of operator IM 
programs is both flexible and appropriate.
Comments Submitted for Questions in Topic G
    G.1. Have any anomalies been identified that require repair through 
various assessment methods (e.g., number of immediate and total repairs 
per mile resulting from ILI assessments, pressure tests, or direct 
assessments)?
    1. INGAA reported that operators have used in-line inspection, 
pressure testing, and direct assessment, with in-line inspection being 
most prevalent. INGAA commented that all three methods have been 
successful at identifying anomalies requiring repair. A number of 
pipeline operators supported INGAA's comments.
    2. AGA and Ameren Illinois stated that all assessment methods used 
by pipeline operators have been used to identify, or have identified, 
anomalies requiring repair. A number of pipeline operators supported 
AGA's comments.
    3. Accufacts recommended that PHMSA publically report the number of 
anomalies discovered and repaired by anomaly type, time to repair, 
state, and assessment method for both HCAs and non-HCAs.
    4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, 
Paiute, and Southwest Gas noted that the transmission pipeline annual 
report includes the number of immediate and scheduled anomalies 
identified by each assessment method.
    5. ITT Exelis Geospatial Systems reported that aerial leak surveys 
using laser technology, which is not one of the assessment methods 
specified in the regulations, have been successful in identifying 
pipeline leaks.
    6. Kern River reported that it did not identify any immediate or 
scheduled repairs from January 1, 2004, through December 31, 2010.
    7. MidAmerican noted that it has used all three allowed assessment 
methods. Approximately 42 percent of the company's pipeline has been 
assessed using direct assessment. All anomalies requiring repair have 
been identified using in-line inspection.
    8. Northern Natural Gas reported that it identified seven immediate 
repair anomalies in the period from January 1, 2004, through December 
31, 2010. The total number of repairs made during this same period 
averaged 0.1 per mile.
    9. An anonymous commenter noted that few leaks are detected using 
subpart J pressure testing.
    10. GPTC reported that it has no data with which to respond to this 
question.
Response to Question G.1 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that all three methods have been successful at identifying 
anomalies requiring repair. However, by its nature, direct assessment 
is a sampling-type assessment method. Hydrostatic pressure testing and 
in-line inspection both assess the entire segment. PHMSA, therefore, 
believes that these methods provide a higher level of assurance (though 
still not 100%) that no injurious pipeline defects remain in the pipe 
after the assessment is completed and anomalies repaired. Based on this 
inherent difference, PHMSA proposes to revise the requirements to: (1) 
Allow direct assessment only if a line is not capable of inspection by 
internal inspection tools; (2) add a newly defined assessment method: 
``spike'' hydrostatic test; (3) add excavation and in situ direct 
examination as an allowed assessment method; and (4) add guided wave 
ultrasonic testing (GWUT) as an allowed assessment method.
    G.2. Should the regulations require assessment using ILI whenever 
possible, since that method appears to provide the most information 
about pipeline conditions? Should restrictions on the use of assessment 
technologies other than ILI be strengthened? If so, in what respect? 
Should PHMSA prescribe or develop voluntary ILI tool types for 
conducting integrity assessments for specific threats such as corrosion 
metal loss, dents and other mechanical damage, longitudinal seam 
quality, SCC, or other attributes?
    1. INGAA, supported by a number of its pipeline operator members, 
noted that ILI is effective, but has its own limitations; pressure 
testing and direct assessment can provide information that ILI cannot. 
INGAA commented that operators must be allowed to use all assessment 
techniques without encumbrances or conditions because all techniques 
are effective.
    2. AGA and a number of its members commented that ILI is one option 
of a variety of methods available to operators and suggested that 
applying additional ILI assessment requirements would hinder operators' 
ability to select the tool with the appropriate capabilities to address 
pipeline threats. AGA commented that this would be inappropriate and 
operators must be allowed to use any of the three assessment methods, 
without conditions, based on the circumstances and threats applicable 
to their pipelines.
    3. Air Products and Chemicals, Inc. opposed a requirement to use 
ILI whenever possible. The company noted

[[Page 20771]]

that one of the benefits of the current IM framework is the flexibility 
it provides to operators in how to achieve regulatory goals. Air 
Products noted that use of alternative methods is already constrained 
by regulation and contended that the existing limitations are adequate 
and it would be inappropriate for PHMSA to specify particular tool 
types for individual threats. Atmos agreed, noting that ILI is not the 
only assessment method applicable to many threats. Atmos noted that ILI 
technology is developing at a rapid pace, and suggested that 
prescribing certain tool types could limit future advancements or cause 
the rate of development to be slowed.
    4. TransCanada opposed requiring use of ILI. The company noted that 
ILI has its advantages, but it also has limitations, and commented that 
operators must be able to select the methods best suited to evaluate 
identified threats, given the wide range of circumstances and threats 
that may be applicable to particular pipeline segments.
    5. NACE International noted that assessments using only ILI do not 
necessarily provide the most information about pipeline conditions; 
other assessment methods may be more appropriate for some threats. NACE 
also noted that not all pipelines are piggable. NACE believes that each 
assessment method has strengths and weaknesses, each should be used 
where appropriate, and overly prescriptive rules can supplant sound 
engineering judgment, stifle innovation, and prevent the development of 
new technologies.
    6. Accufacts commented that all new pipelines should be configured 
to permit ILI and a timetable should be established to convert older 
pipelines for ILI. At the same time, Accufacts cautioned that one 
particular approach to ILI should not be oversold, and suggested that 
limitations on use of certain assessment methods should be strongly 
clarified in regulations. Accufacts suggested that PHMSA needs to 
clarify the major strengths and weaknesses of the various assessment 
methods identified and to improve subpart J, including requiring the 
reporting of hydro testing pressure ranges, both minimum and maximum 
pressures, as a percentage of SMYS when appropriate.
    7. MidAmerican suggested that operators be allowed to address 
threats by category using the guidance in ASME/ANSI B31.8S. MidAmerican 
noted that it cannot use ILI on all of its transmission pipelines, 42 
percent of which have been assessed using direct assessment. 
MidAmerican suggested that operators continue to use their threat 
assessments to determine which pipelines should be retrofitted to 
accommodate ILI.
    8. Northern Natural Gas reported that it uses ILI whenever possible 
but it cannot be used on all of its lines due to their small diameter. 
Northern noted that pressure testing and direct assessment may be more 
appropriate for some threats and that the operator is responsible for 
selecting the best assessment method. Northern opined that the guidance 
on tool selection in ASME/ANSI B31.8S is sufficient.
    9. Texas Pipeline Association and Texas Oil & Gas Association 
recommended that ILI not be the required assessment method of choice 
and that operators continue to have the flexibility to select the 
appropriate assessment method, noting that other methods may be better 
for a particular threat. The associations noted that ILI technology is 
improving rapidly and expressed concern that rulemaking cannot keep 
pace with technological advancement and that prescribing tools could 
result in assessments being conducted with inferior technology.
    10. Thomas M. Lael, an industry consultant, noted that no 
assessment method, including ILI, is perfect. Lael suggested that use 
of alternating methods be required to realize the strengths of all 
methods.
    11. A citizen commenter suggested that use of direct assessment be 
limited, since it does not provide sufficient information about the 
pipeline.
    12. An anonymous commenter noted that requiring ILI would not be 
cost beneficial, because corrosion metal loss is a relatively slow 
process.
    13. GPTC noted that ILI cannot be used on all pipelines and 
recommended that operators have the latitude to select the assessment 
method most appropriate for their pipelines. Oleksa and Associates 
similarly noted that ILI cannot be used on some pipelines.
    14. Paiute and Southwest Gas opposed a requirement to use ILI 
whenever possible. The companies noted that ILI provides current pipe 
conditions but no information on environmental conditions surrounding 
the pipe. They commented that operators should not be discouraged from 
using any appropriate assessment method.
    15. Ameren Illinois opposed requiring the use of ILI, noting that 
it is neither practical nor feasible to require ILI assessments on all 
pipelines.
    16. California Public Utilities Commission recommended that 
pressure testing and ILI be the only methods allowed for IM 
assessments. CPUC suggested that the use of direct assessment be 
limited to confirmatory direct assessments and lines that have been 
pressure tested to subpart J requirements. CPUC further recommended 
that the regulations prescribe acceptable ILI tool types to address 
specific threats.
    17. A private citizen suggested that pressure testing should not be 
allowed as an assessment method because it provides no information 
about anomalies not resulting in leaks or failures. The commenter 
suggested that use of pressure testing should be limited to verifying 
the integrity of new or repaired pipelines.
Response to Question G.2 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that operators should be able to select the methods best suited 
to evaluate identified threats. However, PHMSA believes rulemaking for 
strengthening requirements for the selection and use of assessment 
methods is needed to address specific issues identified from the San 
Bruno incident. PHMSA proposes more prescriptive guidance for the 
selection of assessment methods, especially related to the use of 
direct assessment and to assess for cracks and crack-like defects, as 
indicated in the response to general comments, above. For HCA segments, 
PHMSA proposes that the use of direct assessment as the assessment 
method would be allowed only if the pipeline is not capable of being 
inspected by internal, in-line inspection tools. For non-HCA segments, 
assessments would have to be done within 15 years and every 20 years 
thereafter. To facilitate the identification of non-HCA areas that 
require integrity assessment, PHMSA proposes to define a ``Moderate 
Consequence Area'' or MCA. PHMSA also proposes additional requirements 
for selection and use of internal inspection tools, including a 
requirement to explicitly consider uncertainties such as tool tolerance 
in reported results in identifying anomalies.
    PHMSA disagrees with the suggestion that pressure testing should 
not be allowed as an assessment method. In many circumstances, pressure 
testing is a good indicator of a pipeline's integrity. Although it does 
not assess subcritical defects, it provides assurance of adequate 
design safety margin and can be useful in particular for lines that are 
not piggable.
    G.3. Direct assessment is not a valid method to use where there are 
pipe properties or other essential data gaps. How do operators decide 
whether their

[[Page 20772]]

knowledge of pipeline characteristics and their confidence in that 
knowledge is adequate to allow the use of direct assessment?
    1. Industry commenters, including AGA, INGAA, Texas Pipeline 
Association, Texas Oil and Gas Association, and numerous pipeline 
operators noted that the requirements applicable to direct assessment, 
specified in NACE Standard SP0502-2008 and incorporated into subpart O 
by reference, require a feasibility study to determine if use of direct 
assessment is appropriate. If it cannot be determined during the pre-
assessment phase that adequate data is available, another assessment 
method must be selected. Industry commenters noted that it is the 
operator's responsibility to select an appropriate assessment method.
    2. Paiute and Southwest Gas disagreed with the statement that 
``direct assessment is not a valid method to use where there are pipe 
properties or other essential data gaps.'' The companies noted that the 
data gathered and evaluated conforms to Section 4 of ASME/ANSI B31.8S 
(incorporated by reference) which allows use of conservative proxy 
values when data gaps exist.
    3. California Public Utilities Commission recommended that pressure 
testing and ILI be the only methods allowed for IM assessments. CPUC 
suggested that use of direct assessment be limited to confirmatory 
direct assessments and lines that have been pressure tested to subpart 
J requirements.
Response to Question G.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees that pressure testing and ILI are preferred integrity assessment 
methods, over direct assessment. However, when properly implemented, DA 
can be a valuable integrity assessment tool. PHMSA proposes to retain 
direct assessment as an assessment method where warranted, but proposes 
to revise the requirements in Sec. Sec.  192.921 and 192.937 to allow 
use of direct assessment or other method only if a line is not capable 
of inspection by internal inspection tools.
    G.4. How many miles of gas transmission pipeline have been modified 
to accommodate ILI inspection tools? Should PHMSA consider additional 
requirements to expand such modifications? If so, how should these 
requirements be structured?
    1. A number of industry commenters submitted data concerning the 
number of pipeline miles that have been modified to accommodate ILI:
     INGAA reported that more than 30,000 miles of pipeline 
have been modified across the industry.
     Atmos reported that it has modified approximately 2,800 
miles.
     Northern Natural Gas reported that it has modified 
approximately 2,500 miles.
     MidAmerican reported that it has modified 38 miles.
     Paiute and Southwest Gas reported that they have made 
modifications but have not tracked the total mileage on which they were 
performed.
     Ameren Illinois and Kern River reported that they have 
modified no pipelines. Kern River noted specifically that all of its 
mainline is piggable.
    2. AGA reported that it has no data concerning the number of miles 
modified, but noted that operators are required to assure that new and 
replaced pipelines can accommodate ILI tools. AGA contended that 
modifying pipelines to accommodate ILI tools is more onerous for 
intrastate transmission pipeline operators than for interstate 
operators. A number of operators supported AGA's comments.
    3. Texas Pipeline Association and GPTC reported that they have no 
data with which to respond to this question.
    4. California Public Utilities Commission supported additional 
requirements to expand modifications to accommodate ILI but reported 
that it has no opinion on how these requirements should be structured.
    5. MidAmerican noted that one-third of its 770 miles of 
transmission pipeline is of a diameter smaller than available ILI 
tools.
    6. Northern Natural Gas commented that PHMSA should not consider 
additional requirements to expand modifications of pipelines to 
accommodate ILI tools, and that the inspection method and determination 
to assess additional line segments outside of HCAs should be based on 
specific risk factors and type and configuration of pipeline facility. 
The company noted that some lines cannot be assessed using ILI.
    7. Paiute and Southwest Gas noted that Sec.  192.150 requires that 
newly constructed or replacement pipelines be designed to accommodate 
ILI tools. They contended that the decision to modify other pipelines 
should be an operator decision based on the best assessment method.
    8. Texas Pipeline Association and Texas Oil & Gas Association 
opined that PHMSA does not need to develop additional requirements for 
the modification of transmission pipelines to accommodate ILI tools. 
The associations noted that the regulations already cover this for new 
and replacement pipelines and that there is a financial incentive for 
operators to use ILI tools versus other assessment methods. Atmos 
agreed, also noting that there are numerous advantages to ILI that 
incentivize operators to use that method when they can.
    9. Accufacts commented that PHMSA should report publicly the number 
of miles of transmission pipeline that can be inspected by ILI as well 
as the number of miles inspected by other assessment methods both for 
HCAs and non-HCAs.
Response to Question G.4 Comments
    PHMSA appreciates the information provided by the commenters. In 
its report on the San Bruno incident, the NTSB recommended that all 
natural gas transmission pipelines be configured so as to accommodate 
in-line inspection tools, with priority given to older pipelines 
(recommendation P-11-17). In its initial response to the NTSB 
recommendation, PHMSA stated that implementing this recommendation will 
involve significant technical and economic challenges and is likely to 
require time to implement. Additional data is needed to evaluate this 
issue. Therefore, further rulemaking will be considered separately in 
order to complete this evaluation. PHMSA will review the comments 
received on the ANPRM and will address this issue in the future.
    G.5. What standards are used to conduct ILI assessments? Should 
these standards be incorporated by reference into the regulations? 
Should they be voluntary?
    1. INGAA, supported by a number of its operator members, noted that 
standards are continuously upgraded and improved and recommended that 
PHMSA adopt performance-based language that will allow operators to 
select appropriate standards.
    2. AGA, supported by a number of its members, noted that ILI 
technology is advancing rapidly and it would be unwise to restrict 
innovation by handcuffing it to a slow-developing rulemaking process. 
AGA recommended that PHMSA not adopt ILI standards into the code. 
Ameren Illinois agreed that standards should not be incorporated, 
because to do so would limit operators' ability to use up-to-date 
standards.
    3. GPTC argued that there is no justification to enact additional 
prescriptive regulations for ILI assessments of pipelines. GPTC 
contended that performance standards allow operators to select the best 
approach.

[[Page 20773]]

    4. Atmos, MidAmerican, Northern Natural Gas, Paiute, and Southwest 
Gas all cited one or more of API1163, ASNT ILI-PQ-2005 and RP0102-2002, 
and ASME/ANSI B31.8S as standards used to conduct ILI assessments. All 
agreed that use of industry standards should remain voluntary. Paiute 
and Southwest Gas, in particular, commented that technology is 
developing rapidly, and that incorporating current standards into the 
regulations may hold operators accountable to a level of performance 
that may be outdated.
    5. Texas Pipeline Association and Texas Oil & Gas Association also 
opposed incorporating ILI standards into the regulations. TPA commented 
that there are incentives for operators to take appropriate measures to 
obtain accurate and reliable ILI results.
    6. An anonymous commenter suggested that incorporating standards 
could be counterproductive, since operators would usually stop with the 
required actions. The commenter suggested that a better approach would 
be to require operators to have precise specifications, guidelines, and 
a written process for ILI, none of which should be developed by the 
operator's ILI vendor. The commenter also suggested that a similar 
approach be adopted for stress corrosion cracking direct assessment 
(SCCDA).
    7. California Public Utilities Commission and a private citizen 
recommended that standards be incorporated for mandatory compliance, 
arguing that this is necessary to assure quality and accuracy.
Response to Question G.5 Comments
    PHMSA appreciates the information provided by the commenters. The 
current pipeline safety regulations in 49 CFR 192.921 and 192.937 
require that operators assess the material condition of pipelines in 
certain circumstances and allow use of in-line inspection tools for 
these assessments. Operators are required to follow the requirements of 
ASME/ANSI B31.8S in selecting the appropriate ILI tools. ASME B31.8S 
provides limited guidance for conducting ILI assessments. At the time 
these rules were promulgated, there was no consensus industry standard 
that addressed ILI. Three related standards have been published: API 
STD 1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2010. These 
standards address the qualification of inline inspection systems, the 
procedure for performing ILI, and the qualification of personnel 
conducting ILI, respectively. The incorporation of these standards into 
pipeline safety regulations will promote a higher level of safety by 
establishing consistent standards. Therefore, PHMSA is proposing to 
incorporate these industry standards into the regulations to provide 
better guidance for conducting integrity assessments with in-line 
inspection. PHMSA also encourages and actively supports the development 
of new and better technology for integrity assessments. Therefore, the 
rule also allows the application and use of new technology, provided 
that PHMSA is notified in advance. PHMSA will continue to evaluate the 
need for additional guidance for conducting integrity assessments or 
applying new technology.
    G.6. What standards are used to conduct internal corrosion direct 
assessment (ICDA) and SCCDA assessments? Should these standards be 
incorporated into the regulations? If the commenter believes they 
should be incorporated into the regulations, why? What, if any, 
remediation, hydrostatic test or replacement standards should be 
incorporated into the regulations to address internal corrosion and 
SCC?
    1. INGAA commented that standards exist for ICDA and SCCDA. AGA 
agreed that NACE SP0206 addresses ICDA and SP0204 addresses SCCDA. AGA 
opposed adopting these standards into the regulations, however, 
commenting that a standard must be demonstrated to be effective before 
it can be incorporated. AGA noted that there are long-standing issues 
with the ICDA standard. Numerous pipeline operators provided comments 
supporting the INGAA and AGA comments.
    2. GPTC, Atmos, Ameren Illinois, MidAmerican, Paiute, Southwest 
Gas, Texas Gas Association and Texas Oil & Gas Association all 
referenced one or more of: NACE SP0502, NACE SP0206, ASME/ANSI B31.8S, 
and GRI02-0057. All agreed that the standards should not be 
incorporated by reference, arguing that this would stifle innovation or 
require operators to follow requirements that may become outdated, or 
both. Paiute and Southwest Gas specifically recommended that PHMSA 
collect additional information on industry best practices and compile/
review IM results related to internal corrosion and SCC before taking 
any action towards incorporating the standards.
    3. NACE International reported its conclusion that the existing 
standards for ICDA and SCCDA should be incorporated into regulations. 
NACE also cautioned that overly-prescriptive regulations can prevent 
innovation and development of new technologies.
    4. Northern Natural Gas reported that it used NACE SP0206 in 
developing its ICDA procedures and there would be no impact on the 
company if the standard were adopted into regulations. Northern further 
reported it does not use SCCDA.
    5. Accufacts commented that few technical gains have been made in 
the abilities of direct assessment methods to reliably identify or 
assess at-risk anomalies, especially with regards to SCC.
    6. California Public Utilities Commission argued that pressure 
testing and ILI should be the only assessment methods allowed. The 
Commission contended that direct assessment should be limited to use 
during confirmatory direct assessments and for lines that have been 
pressure tested to subpart J requirements.
    7. An anonymous commenter noted that Kiefner, NACE, and ASTM all 
provide useful references for SCCDA and ICDA.
    8. INGAA, supported by several of its operator members, noted that 
ASME/ANSI B31.8S addresses remediation and pressure testing. INGAA 
recommended that PHMSA adopt the 2010 version of this standard, arguing 
that it is improved over the 2004 standard that is currently 
incorporated by reference into Section 192.7 and that it addresses 
near-neutral SCC. The 2010 edition also includes specific guidance for 
SCC mitigation by means of hydrostatic pressure testing in the event 
SCC is identified on a pipeline.
    9. MidAmerican reported that it uses ASME B31G to determine 
remaining wall strength and that it remediates conditions in accordance 
with Sec.  192.933(d) and ASME/ANSI B31.8S.
Response to Question G.6 comments
    PHMSA appreciates the information provided by the commenters. 
Section 192.927 specifies requirements for gas transmission pipeline 
operators who use ICDA for IM assessments. The requirements in Sec.  
192.927 were promulgated before there were consensus standards 
published that addressed ICDA. Section 192.927 requires that operators 
follow ASME/ANSI B31.8S provisions related to ICDA. PHMSA has reviewed 
NACE SP0206-2006 and finds that it is more comprehensive and rigorous 
than either Sec.  192.927 or ASME B31.8S in many respects. In addition, 
Section 192.929 specifies requirements for gas transmission pipeline 
operators who use SCCDA for IM assessments. The requirements in Sec.  
192.929 were promulgated before there were consensus industry standards 
published that addressed SCCDA. Section 192.929 requires that operators 
follow Appendix A3 of ASME/ANSI B31.8S. This appendix provides some 
guidance for

[[Page 20774]]

conducting SCCDA, but is limited to SCC that occurs in high-pH 
environments. Experience has shown that pipelines also can experience 
SCC degradation in areas where the surrounding soil has a pH near 
neutral (referred to as near-neutral SCC). NACE Standard Practice 
SP0204-2008 addresses near-neutral SCC in addition to high-pH SCC. In 
addition, the NACE recommended practice provides technical guidelines 
and process requirements which are both more comprehensive and rigorous 
for conducting SCCDA than either Sec.  192.929 or ASME/ANSI B31.8S. 
Therefore, PHMSA is proposing to incorporate these industry standards 
into the regulations to provide better guidance for conducting 
integrity assessments with ICDA or SCCDA. PHMSA will continue to 
evaluate the need for additional guidance for conducting integrity 
assessments.
    G.7. Does NACE SP0204-2008 (formerly RP0204), ``Stress Corrosion 
Cracking Direct Assessment Methodology'' address the full life cycle 
concerns associated with SCC?
    1. INGAA suggested NACE SP0204, by itself, does not address the 
full life cycle concerns of SCC but in combination with ASME/ANSI 
B31.8S the full life cycle concerns are addressed. A number of pipeline 
operators supported INGAA's comments.
    2. AGA, supported by a number of its members, suggested PHMSA 
should determine whether NACE SP0204 addresses full life cycle 
concerns.
    3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association, 
and Ameren Illinois commented it was not clear what PHMSA meant by 
``full life cycle concerns.''
    4. NACE International reported that SP0204 does not address the 
full life cycle concerns of SCC; however, NACE noted that it has 
developed a 2011 ``Guide to Improving Pipeline Safety by Corrosion 
Management'' which will be converted into a NACE standard.
    5. MidAmerican reported its conclusion that NACE SP0204 does 
address full life cycle concerns.
    6. Paiute and Southwest Gas reported their conclusion that the 
existing standards are adequate, but deferred to NACE concerning the 
breadth of coverage of NACE standards.
Response to Question G.7 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
believes that NACE SP0204-2008 is the best available guidance and is 
proposing to incorporate this industry standard into the regulations 
for conducting integrity assessments with SCCDA. In addition, other 
proposed requirements for integrity assessments and remediation in 
Sec. Sec.  192.710, 192.713, 192.624, and subpart O provide greater 
assurance that the full life cycle concerns associated with SCC are 
addressed.
    G.8. Are there statistics available on the extent to which the 
application of NACE SP0204-2008, or other standards, have affected the 
number of SCC indications operators have detected and remediated on 
their pipelines?
    1. Industry commenters responding to this question unanimously 
noted that no statistics have been collected on the use of NACE SP0204. 
INGAA noted, in addition, that the SCC Joint Industry Project (JIP) 
represents the experience of operators of 160,000 miles of gas 
transmission pipeline.
    2. Paiute and Southwest Gas reported that they have not identified 
any SCC on their pipeline systems.
    3. An anonymous commenter noted that there has been one incident 
attributed to factors not addressed in current standards. The commenter 
noted that the only common factors among SCC colonies was high soil 
resistivity and disbanded coating.
Response to Question G.8 Comments
    PHMSA appreciates the information provided by the commenters. As 
described in the response to Question G.6, PHMSA is proposing to 
incorporate NACE SP0204-2008 into the regulations. PHMSA will continue 
to gather information in this area and will evaluate the need for more 
specific requirements or guidance to address the threat of SCC.
    G.9. Should a one-time pressure test be required to address 
manufacturing and construction defects?
    1. INGAA and a number of its pipeline operators argued that this 
should be a case-by-case decision guided by INGAA's Fitness for Service 
protocol. INGAA noted that new pipelines require a part 192, subpart J, 
pressure test while older pipelines may have been strength tested.
    2. AGA, supported by a number of its pipeline operators, opined 
that a one-time pressure test is sufficient. AGA noted that Congress 
accepted the stability of pipelines that had undergone a post 
construction pressure test.
    3. GPTC argued that a one-time pressure test is sufficient; 
however, such a test should not be mandated for pipelines not tested 
after construction unless a significant risk has been demonstrated. 
GPTC noted that manufacturing and construction defects are not time-
related.
    4. American Public Gas Association objected to any requirement for 
a one-time pressure test, noting that it is not practical to conduct 
such a test on most transmission pipelines operated by municipal 
pipeline operators.
    5. Atmos noted that the decision to perform one-time pressure tests 
to address manufacturing and construction defects requires more 
information and consideration than can be conveyed in response to a 
single question. Atmos reported that it could not determine if the one-
time pressure test requirement would apply to all pipeline segments or 
to pipelines with certain characteristics. Some of Atmos' pipelines 
could not be removed from service for testing without impacts on 
customers.
    6. Ameren Illinois argued that no one-time pressure test should be 
required, noting that a pressure test is already required before a 
pipeline is placed in service.
    7. Northern Natural Gas argued that a one-time pressure test should 
not be required in all cases. Northern noted that assessment of 
manufacturing and construction defect threats should be determined 
based on the risk level and pipeline type for pipeline segments do not 
have an existing pressure test.
    8. MidAmerican opined that a one-time pressure test should be a 
requirement for manufacturing and construction defects, noting defects 
that survive a pressure test are unlikely to fail during the useful 
life of the pipeline.
    9. Oleksa and Associates noted that: (1) A one-time pressure test 
is all that is needed for manufacturing and construction defects; (2) 
an in-service pipeline should only be pressure tested if there is clear 
reason to believe a strength test would be beneficial; and (3) many 
pipelines operate at such low levels of stress that a strength test is 
not necessary.
    10. Paiute and Southwest Gas commented that a pressure test should 
be conducted in accordance with subpart J when initially placing a 
pipeline in service. The operators reported that they support the 
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 
which will require systematic pressure testing (or other alternative 
methods of equal or greater effectiveness) of certain, previously 
untested transmission pipelines located in HCAs and operating at a 
pressure greater than 30% SMYS. Texas Pipeline Association and Texas 
Oil & Gas Association agreed, noting that testing of new pipelines is 
already required and the Act requires use of pressure testing or 
alternate means to verify MAOP.

[[Page 20775]]

    11. Thomas Lael and California Public Utilities Commission argued 
that all pipelines should be subjected to a pressure test. CPUC noted 
that an unspecified technical paper published by Kiefner shows that a 
pressure test to 1.25 times MAOP will be sufficient to demonstrate the 
stability of manufacturing and construction defects and girth welds.
    12. The NTSB recommended that PHMSA amend part 192 so that 
manufacturing and construction defects can only be considered stable if 
a gas pipeline has been subjected to a post-construction hydrostatic 
pressure test of at least 1.25 times the MAOP.
    13. Accufacts suggested that a requirement for a one-time pressure 
test is needed, noting the NTSB safety recommendations issued following 
San Bruno made it clear that there are problems with the current IM 
regulations, especially as they relate to systems that were in 
operation before the implementation of federal regulations.
    14. A private citizen suggested that a one-time pressure test or 
reduction of MAOP should be required for all low-frequency electric 
resistance welded (LFERW) pipe.
    15. A private citizen suggested that a one-time pressure test 
conducted in combination with ILI should be required as a baseline for 
subsequent ILI inspections.
    16. An anonymous commenter opined that no one-time pressure test is 
needed unless there is a history of seam failure or SCC.
Response to Question G.9 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of comments support performance of a one-time pressure test to 
address manufacturing and construction defects. The ANPRM requested 
comments regarding proposed changes to part 192 regulations that would 
repeal 49 CFR 192.619(c) and the NTSB issued recommendations to repeal 
49 CFR 192.619(c) for all gas transmission pipelines (P-11-14) and to 
require a pressure test before concluding that manufacturing- and 
construction-related defects can be considered stable (P-11-15). In 
addition, Section 23 of the Act requires issuance of regulations 
regarding the use of tests to confirm the material strength of 
previously untested natural gas transmission lines.
    An Integrity Verification Process (IVP) workshop was held in 2013. 
At the workshop, PHMSA, the National Association of State Pipeline 
Safety Representatives, and various other stakeholders presented 
information and comments were sought on a proposed IVP that will help 
address these issues. Key aspects of the proposed IVP process include 
criteria for establishing which pipe segments would be subject to the 
IVP, technical requirements for verifying material properties where 
adequate records are not available, and technical requirements for re-
establishing MAOP where adequate records are not available or the 
existing MAOP was established under Sec.  192.619(c). Comments were 
received from the American Gas Association, the Interstate Natural Gas 
Association of America, and other stakeholders and addressed the draft 
IVP flow chart, technical concerns for implementing the proposed IVP, 
and other issues. The detailed comments are available on Docket No. 
PHMSA-2013-0119. PHMSA considered and incorporated the stakeholder 
input, as appropriate into this NPRM, which proposes requirements to 
address pipelines that established MAOP under 49 CFR 192.619(c), 
manufacturing and construction defect stability, verification of MAOP 
(where records that establish MAOP are not available or inadequate), 
and verification and documentation of pipeline material for certain 
onshore, steel, gas transmission pipelines.
    G.10. Have operators conducted quality audits of direct assessments 
to determine the effectiveness of direct assessment in identifying 
pipeline defects?
    1. INGAA, AGA, GPTC, and numerous pipeline operators noted that 
direct assessment is a cyclical process that continually incorporates 
analysis of information made available from the direct and indirect 
assessment tools used. The direct assessment process requires that more 
restrictive criteria be applied on first use and as operators become 
more experienced with the methodology and gather more data on the 
pipeline, more informed pipeline integrity decisions are made. The 
commenters stated that operators using the direct assessment process 
must continuously assess the effectiveness of the methodology.
    2. Paiute and Southwest gas commented that operators confirm the 
findings of the pre-assessment and indirect assessment steps as part of 
the four-step direct assessment process. Validation digs are required 
to confirm the effectiveness of the direct assessment process.
    3. Texas Pipeline Association and Texas Oil & Gas Association noted 
that direct examinations are made as part of every direct assessment. 
In Texas, operators have generally been required by the Railroad 
Commission to demonstrate comparisons of direct assessment results to 
ILI results on a portion of their pipeline where both have been 
performed. The associations contended that this process of validating 
should be considered a quality audit.
    4. Northern Natural Gas agreed that verification of the 
effectiveness of direct assessment is already a part of the required 
post-assessment step of the four-step direct assessment process. Ameren 
Illinois agreed that this process is effectively a quality audit.
    5. Atmos reported that records are kept of the indicated anomalies 
and the actual anomalies discovered through direct examination, thus 
assuring the quality and validation of direct assessments.
    6. Accufacts opined that there appear to be serious deficiencies in 
the application of direct assessment on gas pipelines.
    7. An anonymous commenter noted that direct assessment, if used 
correctly, is informative and proactive, and best suited to identify 
preventive and mitigative actions and to establish assessment 
intervals.
Response to Question G.10 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of comments state that quality audits are performed for direct 
assessments, however, PHMSA believes, as one comment suggests, that 
there are weaknesses in the use of direct assessments. For example, 
SCCDA is not as effective, and does not provide an equivalent 
understanding of pipe conditions with respect to SCC defects, as ILI or 
hydrostatic pressure testing. Accordingly, PHMSA proposes to revise the 
requirements in Sec. Sec.  192.921 and 192.937 for direct assessment to 
allow use of this method only if a line is not capable of inspection by 
internal inspection tools.
    G.11. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.

[[Page 20776]]

    No comments were received in response to this question.

H. Valve Spacing and the Need for Remotely or Automatically Controlled 
Valves

    The ANPRM requested comments regarding proposed changes to the 
requirements for sectionalizing block valves. Gas transmission 
pipelines are required to incorporate sectionalizing block valves. 
These valves can be used to isolate a section of the pipeline for 
maintenance or in response to an incident. Valves are required to be 
installed at closer intervals in areas where the population density 
near the pipeline is higher.
    Sectionalizing block valves are not required to be remotely-
operable or to operate automatically in the event of an unexpected 
reduction in pressure (e.g., from a pipeline rupture). Congress has 
previously required PHMSA to ``assess the effectiveness of remotely 
controlled valves to shut off the flow of natural gas in the event of a 
rupture'' and to require use of such valves if they were shown 
technically and economically feasible.\36\ The NTSB has also issued a 
number of recommendations concerning requirements for use of automatic- 
or remotely-operated mainline valves, including one following a 1994 
pipeline rupture in Edison, NJ.\37\ The incident in San Bruno, CA on 
September 9, 2010, has raised public concern about the ability of 
pipeline operators to isolate sections of gas transmission pipelines in 
the event of an accident promptly and whether remotely or automatically 
operated valves should be required to assure this.
---------------------------------------------------------------------------

    \36\ Accountable Pipeline Safety and Partnership Act of 1996, 
Public Law 104-304.
    \37\ National Transportation Safety Board, ``Texas Eastern 
Transmission Corporation Natural Gas Pipeline Explosion and Fire, 
Edison, New Jersey, March 23, 1994,'' PB95-916501, NTSB/PAR-95/01, 
January 18, 1995.
---------------------------------------------------------------------------

    The ANPRM then listed questions for consideration and comment. The 
following are general comments received related to the topic as well as 
comments related to the specific questions:
General Comments for Topic H
    1. INGAA argued that while valves, spacing, and selection are 
important, public safety requires a broader review of incident 
responses and consequences. Performance-based Incident Mitigation 
Management (IMM), using valves and other tools, will, according to 
INGAA, improve incident response, reduce incident duration and minimize 
adverse impacts. IMM plans identify comprehensive actions that improve 
mitigation performance and minimize overall incident impact. These 
plans cover various aspects of response, including how operators detect 
failures, how they place and operate valves, how they evacuate natural 
gas from pipeline segments, and how they prioritize coordination 
efforts with emergency responders. A number of pipeline operators 
supported INGAA's comments, including Panhandle, TransCanada, Spectra 
Williams, Southern Star, and others.
    2. AGA submitted a white paper that discussed potential benefits 
associated with remote control valves and automatic shutoff valves; 
however, the paper acknowledged that these valves will not prevent 
incidents. A number of pipeline operators supported AGA's comments.
    3. APGA reported automatic or remotely-controlled valves are not 
practical for municipal pipeline operators because they do not have 
remote monitoring or control of their pipelines. APGA also cautioned 
that the use of automatic valves could lead to false closures, an 
unintended and adverse consequence.
    4. Atmos commented that the existing requirements for valve spacing 
allow for safe and reliable service to its customers. The company noted 
that requiring the installation of remote control valves or automatic 
shutoff valves would add minimal value to the overall safety and 
operation of its transmission pipeline systems. In addition, industry 
studies have concluded that remote or automatic features on block 
valves would not reduce injuries or fatalities associated with an 
incident.
    5. MidAmerican commented that installation of automatic shutoff 
valves would be costly, have minimal impact on improving safety, and 
could cause customer outages on its pipeline system. At the same time, 
MidAmerican acknowledged that some applications of remote/automatic 
control valves could have merit, but that the election should lie with 
the operator given the complexity of pipeline systems and other factors 
that bear on that decision. MidAmerican reported its conclusion that 
ASME/ANSI B31.8S provides adequate guidance for the installation of 
sectionalizing valves. While MidAmerican opposes a requirement to 
install automatic or remotely-controlled valves, the company suggested 
factors PHMSA should consider if it decides to adopt such a 
requirement. Specifically, PHMSA should allow operators flexibility in 
deciding between automatic and remote valves and should clarify when 
action on a pipeline is considered a new installation versus a repair 
or replacement in-kind.
    6. TransCanada noted that industry studies have shown automatic or 
remote block valves do not prevent incidents and have a minimal effect 
on significant consequences, since most of the human impacts from a 
rupture occur in the first few seconds, well before any valve 
technology could reduce the flow of natural gas. TransCanada supports 
the use of Incident Mitigation Management (IMM) to improve incident 
response, reduce incident duration, and minimize adverse impacts.
    7. Chevron argued operators should have the flexibility to select 
the most effective measures based on specific locations, risks, and 
conditions of the pipeline segment. Chevron noted that the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011 requires a 
study of incident response in HCAs that must consider the swiftness of 
leak detection and pipeline shut-down capabilities and the location of 
the nearest personnel. The study must also evaluate the costs, risks, 
and benefits of installing automatic or remote controlled shut-off 
valves.
    8. A private citizen suggested that periodic drills be held with 
local emergency responders, pipeline operators should provide 
specialized equipment to local responders in densely populated areas, 
and pipeline operators pay a fee to those municipalities to support 
incident response. The commenter further recommended that leak 
detection analyses be computerized.
    9. Dominion East Ohio contended that current regulations are 
adequate and that automatic shutoff valves and remote control valves 
are an important preventive and mitigative measure to consider using. 
However, these valves do not prevent accidents and have very limited 
impact in preventing injuries and deaths caused by an initial pipeline 
failure.
    10. Accufacts suggested that further prescriptive regulation is 
required concerning the placement, selection, and choice of manual, 
remotely-controlled, or automatic shutoff valves.
    11. The Pipeline Safety Trust (PST) questioned the conclusions of 
the DOT study, ``Remotely Controlled Valves on Interstate Natural Gas 
Pipelines, (Feasibility Determination Mandated by the Accountable 
Pipeline Safety and Partnership Act of 1996), September 1999, which 
concluded that remote control valves were and remain economically 
unfeasible. The PST noted that the study also stated that there could 
be a potential benefit in terminating the gas flow to a rupture

[[Page 20777]]

expeditiously particularly in heavily populated and commercial areas. 
PST suggested PHMSA commission an independent analysis to reach a 
conclusion regarding whether to require these valves.
    12. A private citizen suggested that local authorities regularly 
review incidents in densely populated areas, as self-policing by 
pipeline operators is insufficient. The commenter also recommended that 
pipeline construction and modifications be subject to signoff by a 
licensed professional engineer and be certified for compliance with 
applicable regulations by a corporate officer subject to criminal 
penalties, in order to reduce the incentive to cut corners.
    13. Northern Natural Gas and a private citizen recommended that the 
current one-call exemptions for government agencies be eliminated.
Comments Submitted for Questions in Topic H
    H.1. Are the spacing requirements for sectionalizing block valves 
in Sec.  192.179 adequate? If not, why not and what should be the 
maximum or minimum separation distance? When class locations change as 
a result of population increases, should additional block valves be 
required to meet the new class location requirements? Should a more 
stringent minimum spacing of either remotely or automatically 
controlled valves be required between compressor stations? Under what 
conditions should block valves be remotely or automatically controlled? 
Should there be a limit on the maximum time required for an operator's 
maintenance crews to reach a block valve site if it is not a remotely 
or automatically controlled valve? What projected costs and benefits 
would result from a requirement for increased placement of block 
valves?
    1. AGA and a number of pipeline operators contended that the 
existing requirements in Sec.  192.179 are adequate. AGA noted that 
studies have shown there is no safety benefit to having more remote or 
automatic valves and operators should be permitted to determine the 
need for additional valves and spacing. AGA contended that there is no 
safety reason to change the existing regulation and argued that remote 
or automatic valves should not be mandated for any specific set of 
circumstances, since they are only one option for pipeline shutdown.
    2. Texas Pipeline Association and Texas Oil & Gas Association 
commented that spacing requirements for natural gas transmission lines 
have been shown to be adequate for emergency situations. Both 
associations observed that block valves are not in place to prevent 
accidents and that the greatest impact of an accident is from the 
initial gas release, before automatic or remote valves could actuate. 
The associations also noted that the addition of more block valves 
would increase the risk to aboveground infrastructure.
    3. Accufacts contended that the existing spacing requirements are 
inadequate and noted that valve spacing plays a significant role in the 
``isolation blowdown'' time, or the time to depressurize a gas pipeline 
segment once isolation valves are closed after a rupture. Accufacts 
also recommended that additional sectionalizing valves be required when 
class locations change.
    4. Iowa Utilities Board (IUB) suggested that ease of access and the 
time to respond should be factors relevant to a decision as to whether 
to install automatic or remote valves. IUB noted that the 
considerations are different for valves in remote areas compared to 
urban valves.
    5. California Public Utilities Board reported that the issue of 
valve spacing is under review by the State.
    6. A private citizen suggested that valves be required at one-mile 
intervals in densely populated urban areas and that they close 
automatically in the event of an incident, since the duration of the 
fire resulting from an incident is directly proportional to the volume 
of gas between valves. AGA commented that it is not the amount of gas 
between valves but rather it is the volume between a valve and a 
rupture that determines the volume released.
    7. Wyoming County Pennsylvania's Commissioners suggested that it is 
necessary to modify separation distances and to establish adequate 
distances for gathering lines, including in Class 1 areas. The 
Commissioners acknowledged that the spacing required for Class 3 
locations may be more acceptable than the spacing required for Class 1 
areas, but noted that it will take longer to reach a block valve with 
10 mile spacing in Pennsylvania's Marcellus Shale regions.
    8. An anonymous commenter responded that current valve spacing 
requirements are adequate and suggested that automation be required if 
it would take 20 to 30 minutes to respond to a mainline valve.
    9. AGA, supported by a number of pipeline operators, noted that 
operators evaluate the need for additional block valves when they 
become aware of changes in class location.
    10. Atmos commented that the need for additional block valves 
should be evaluated when class locations change, if pipe replacement is 
needed to comply with the new class locations. Atmos recommended valve 
installations, if any, should only be required within the replaced 
pipeline section. Atmos further recommended that automatic or remote 
valves should not be required between compressor stations due to the 
risk of false closures and the extensive modifications that would be 
required.
    11. MidAmerican opposed a requirement to install new block valves 
when a class location changes or to establish more stringent spacing 
requirements, noting that ASME/ANSI B31.8 provides adequate guidance 
for block valve considerations. Texas Pipeline Association, Texas Oil & 
Gas Association, and Northern Natural Gas agreed, noting that the 
required class location study includes consideration of current spacing 
as well as other criteria.
    12. The Commissioners of Wyoming County Pennsylvania stated that it 
is imperative that a suitable number of additional block valves be 
required when population increases and class location changes, arguing 
that this is necessary to assure adequate public safety measures are in 
place.
    13. An anonymous commenter suggested that new valves should not be 
required when HCA or class location boundaries change, noting that such 
changes occur rather frequently.
    14. Northern Natural Gas argued that a prescriptive standard for 
valve spacing may not necessarily provide additional risk reduction, 
noting that many Class 2 and 3 locations are short pipe segments within 
an extended Class 1 location.
    15. Texas Pipeline Association and Texas Oil & Gas Association 
noted that more block valves would not decrease the damage from a 
pipeline accident, noting that PHMSA studies have shown that fatalities 
and significant property damage occur within 3 minutes of a pipeline 
rupture while a remotely-operated valve takes 10 minutes to close. This 
and other studies have shown the only benefit to adding more valves is 
reducing the amount of gas lost in an accident.
    16. Accufacts contended that a more scientific discussion will 
demonstrate a maximum spacing of eight miles will provide sufficient 
risk reduction.
    17. MidAmerican suggested that block valves should be automatic or 
remotely-operated only when adequate response times cannot be achieved 
by operator personnel. When response times are adequate, MidAmerican 
contended that use of automatic or remote valves should be at the 
operator's discretion.
    18. Northern Natural Gas suggested that the decision to use remote 
or automatic shut-off valves should be

[[Page 20778]]

based on the operator's risk assessment and should be made, by the 
operator, on a case-by-case basis.
    19. Paiute and Southwest Gas argued that operators should have the 
flexibility to evaluate and determine whether remote or automatic 
valves would be beneficial. The companies noted that Sec.  192.935 
already requires the consideration of additional valves as a preventive 
and mitigative measure.
    20. Accufacts contended that decisions on valve spacing and whether 
they should be manual, remote, or automatic will be dependent on the 
time established for first responders to safely enter an actual gas 
transmission impact zone following rupture. Accufacts noted that 
California has set a goal of 30 minutes for first response time.
    21. A private citizen suggested that automatic shutoff valves 
should be used in densely populated areas because they provide the most 
rapid response.
    22. The Commissioners of Wyoming County Pennsylvania suggested that 
standardization is necessary with remotely and automatically controlled 
shutoffs. The Commissioners contended that the operator needs to employ 
remote or automatic valves when transmission and gathering lines are 
routed through areas that are not easily accessible.
    23. INGAA noted that Sec.  192.620 requires a one-hour time frame 
for closing a valve, and contended this is practical for valves that 
would isolate pipelines in HCAs and consistent with requirements for 
alternative MAOP in Sec.  192.620. A number of pipeline operators 
supported INGAA's comments.
    24. Atmos suggested that mandating a minimum time to reach a valve 
site is impractical, because many variables exist in a dynamic state 
that affect an operator's ability to reach a block valve site.
    25. MidAmerican opposed a specified time frame for response to a 
valve site, noting that operators should respond in an expedient manner 
without specified time limits.
    26. Northern Natural Gas suggested PHMSA consider a two-hour 
response time for valves in HCA.
    27. Texas Pipeline Association and Texas Oil & Gas Association 
noted that conditions determine how quickly an operator can reach a 
valve site in the event of an incident and operators make every effort 
to respond expeditiously when an incident occurs. The associations 
opposed adoption of a required response time.
    28. TransCanada reported its conclusion that having personnel on 
site within one hour is reasonable for planning purposes. If this 
cannot be met, TransCanada suggested that possible valve automation 
should be required.
    29. The Commissioners of Wyoming County Pennsylvania reported their 
conclusion that there would be value in establishing a maximum response 
time, especially in Class 1 locations where block valves may be 10 
miles apart.
    30. INGAA and a number of its pipeline operator members noted that 
studies have shown consistently that there is no value in installing 
additional block valves or in automating valves. They suggested that it 
would be more beneficial to apply resources that would be required to 
comply with any new requirements in this area towards preventing 
accidents.
    31. MidAmerican reported that installing additional block valves 
would entail significant costs and suggested that increasing the number 
of valves could cost in excess of $40 million for its pipeline system. 
Northern Natural Gas agreed that costs could be substantial, without 
providing a specific estimate for its pipeline system.
    32. Paiute and Southwest Gas estimated that costs to install new 
valves could range from $100,000 to $1 million per installation.
    33. An anonymous commenter estimated that retrofitting a 36-inch 
valve for remote operation would cost approximately $30,000 plus 
subsequent maintenance costs.
    34. Accufacts noted that the San Bruno accident demonstrated that 
there is a cost associated with not properly spacing, installing or 
automating valves in high consequence areas.
    H.2. Should factors other than class location be considered in 
specifying required valve spacing?
    1. INGAA, AGA, GPTC and several pipeline operators took the 
position that no new requirements are needed. These associations argued 
that Sec.  192.179 provides appropriate minimum standards and reported 
that operators install additional valves in accordance with their 
integrity management plans or other factors that they consider 
voluntarily.
    2. Paiute and Southwest Gas opined that no additional criteria are 
needed. They noted that numerous industry studies have shown that there 
is little or no safety benefit to installing additional automatic or 
remote valves. They suggested that operators should have the 
flexibility to determine, based on local circumstances, where 
additional valves are needed.
    3. Atmos suggested that valve accessibility be given more 
consideration, noting that installing valves in locations that provide 
improved accessibility could lead to spacing greater than allowed under 
current regulations. Atmos further suggested that environmental factors 
such as water crossings and areas prone to flooding should be taken 
into consideration.
    4. MidAmerican opined that additional factors should be considered 
and pointed to ASME/ANSI B31.8 for examples.
    5. Accufacts concluded that additional factors need to be taken 
into consideration, noting that protection of identified sites in Class 
1 and 2 locations will require shorter valve spacing than is currently 
required by regulations.
    6. The California Public Utilities Commission noted that there are 
numerous factors to be considered that affect response time, and that 
this issue is under review by the State.
    7. The Texas Pipeline Association, Texas Oil & Gas Association, and 
Commissioners of Wyoming County Pennsylvania suggested that factors 
other than class location should not be added to the regulations. They 
noted that class location serves as a surrogate for the level of risk 
posed by a pipeline.
    H.3. Should the regulations be revised to require explicitly that 
new valves must be installed in the event of a class location change to 
meet the spacing requirements of Sec.  192.179? What would be the costs 
and benefits associated with such a change?
    1. INGAA and a number of its pipeline operator members opposed 
applying Sec.  192.179 requirements retroactively to class location 
changes. INGAA suggested that, rather than absorbing the cost of 
installing new valves, other preventive and mitigative measures applied 
through an integrity management plan would produce greater benefits.
    2. AGA and a number of its members opposed requiring new valves be 
installed when class location changes, arguing that no safety benefit 
will result.
    3. Northern Natural Gas expressed its opinion that current 
regulations are adequate, noting that class location change studies 
require consideration of block valve spacing.
    4. MidAmerican opined that the existing regulations are adequate 
and noted that ASME/ANSI B31.8 provides other factors for 
consideration.
    5. GPTC expressed its belief that existing requirements are 
adequate, noting that operators voluntarily consider other factors in 
establishing valve locations.
    6. Atmos suggested that PHMSA not require the installation of new 
valves

[[Page 20779]]

due to changes in class location, but stated the agency should consider 
the need for additional block valves if pipe replacement is needed as a 
result of the change.
    7. Accufacts suggested that new valves should be required following 
class location changes, but suggested that a reasonable time should be 
provided for such valves to be installed and operational.
    8. The Texas Pipeline Association and Texas Oil & Gas Association 
commented that no safety benefit has been demonstrated for the 
installation of additional valves. The associations suggested that 
installing additional valves could be counterproductive, since more 
above-ground valves could pose an additional risk to the public.
    9. The California Public Utilities Commission opined that the 
regulations should require explicitly that additional valves be 
installed when class location changes, but expressly withheld an 
opinion on related costs.
    10. A private citizen suggested that all requirements related to 
class location should apply when class location changes, unless PHMSA 
adopts an expanded definition for HCA to replace class location 
considerations.
    11. An anonymous commenter stated that most operators anticipate 
changes to Class 3 or 4 when pipelines are designed and constructed. 
The commenter estimated that installing a new 36-inch valve would cost 
$70 to $100 thousand, not including down time and lost product.
    12. The Commissioners of Wyoming County Pennsylvania commented that 
the regulations need to be revised to explicitly require that new 
valves be installed when class locations change. The Commissioners 
suggested that this needs to extend to both transmission and gathering 
lines in Class 1 areas.
    H.4. Should the regulations require addition of valves to existing 
pipelines under conditions other than a change in class location?
    1. INGAA and a number of pipeline operators noted that studies have 
indicated valve spacing has limited impact on the duration of an 
incident. INGAA suggested that a performance-based approach to incident 
mitigation management would better inform valve placement.
    2. AGA opposed requiring additional valves under any scenario. A 
number of pipeline operators supported AGA's comments.
    3. Accufacts suggested that new valves should be installed when a 
site becomes an HCA regardless of class location, but a reasonable time 
should be allowed for such valves to be installed and become 
operational.
    4. Ameren Illinois opposed requiring new valves under other 
conditions, opining that existing requirements are adequate.
    5. GPTC and Atmos commented that existing regulations are a 
sufficient baseline for determining valve location, noting that 
operators often use more stringent spacing criteria during initial 
construction.
    6. MidAmerican opposed requiring that installation of new valves on 
existing pipelines for any reason other than a class location change, 
noting that ASME/ANSI B31.8 provides additional factors for operators 
to consider in determining valve location.
    7. Northern Natural Gas noted that existing regulations require 
that operators consider additional valves as a preventive and 
mitigative measure and expressed its conclusion that this requirement 
is sufficient.
    8. Paiute and Southwest Gas suggested that operators should have 
the flexibility to evaluate and determine where remotely-controlled or 
automatic valves would be beneficial. The companies noted that Sec.  
192.935 requires the consideration of additional valves as a preventive 
and mitigative measure and industry studies indicate little or no 
safety benefit to installing additional valves.
    9. The California Public Utilities Commission suggested that 
conditions that would impede access to a valve may need to be 
considered in determining valve placement.
    H.5. What percentage of current sectionalizing block valves are 
remotely operable? What percentage operate automatically in the event 
of a significant pressure reduction?
    1. INGAA estimated that 40 to 50 percent of mainline block valves 
are remotely-operated or automatic. INGAA did not provide an estimate 
specifically for automatic valves. INGAA noted that application of 
Incident Mitigation Management would lead operators to conclusions as 
to whether a valve should be remote or automatic. A number of pipeline 
operators supported INGAA's comments.
    2. AGA and GPTC reported that they have no data with which to 
respond to this question.
    3. Ameren Illinois reported that it has no remotely-controlled 
valves.
    4. Atmos reported that remote and automatic valves are not 
installed routinely. Remotely-controlled valves are installed on a 
small number of select pipelines, representing approximately 0.1 
percent of all valves.
    5. Kern River reported that 66 percent of its mainline block 
valves, and all block valves in HCA, are remotely-controlled.
    6. MidAmerican reported that less than one percent of its valves 
are remotely-controlled and a similarly small percentage of them are 
automatic.
    7. Northern Natural Gas reported that remotely-controlled valves 
are located only at compressor stations on its pipeline system.
    8. Paiute reported that less than 10 percent of the valves on its 
system are remotely-controlled. Paiute has no automatic valves.
    9. Southwest Gas reported that it has no remotely-controlled or 
automatic valves, due to the urban nature of its pipeline system.
    10. Texas Pipeline Association reported that a limited survey of 
its members indicated the number of remotely-controlled valves varies 
from 1 to 18 percent; the number of automatic valves varies from zero 
to 18 percent.
    H.6. Should PHMSA consider a requirement for all sectionalizing 
block valves to be capable of being controlled remotely?
    1. INGAA and a number of pipeline operators opposed consideration 
of such a requirement. They commented that no one solution should be 
mandated and Incident Mitigation Management should guide operators to 
decisions as to which valves should be remote or automatic.
    2. AGA and a number of pipeline operators also opposed 
consideration of such a requirement, noting remotely-controlled valves 
are only one option for shutting down a pipeline.
    3. Accufacts opposed such a generic requirement, noting small-
diameter gas transmission pipelines may not merit automation because of 
the science of pipeline diameter rupture associated with high heat flux 
releases.
    4. GPTC opined that remotely-controlled valves do not improve 
safety, thus there is no basis for requiring their use. GPTC noted that 
operators voluntarily consider many factors in establishing valve 
locations.
    5. Atmos opposed consideration of this requirement, noting there 
are issues with false closures and the costs of conversion or 
installation are extensive. Atmos also noted that industry studies have 
shown no increase in safety from having more remotely-controlled or 
automatic valves.
    6. Kern River opined that this should be an operator decision, 
noting that integrity management regulations require the consideration 
of remote or automatic valves as part of identifying preventive and 
mitigative measures.

[[Page 20780]]

    7. MidAmerican strongly opposed requiring all sectionalizing block 
valves to be remotely controlled. MidAmerican stated that the location 
and type of valve should be based on an engineering assessment. A 
requirement that all valves be remote would increase costs and may 
provide disincentives to installation of additional valves.
    8. Northern Natural Gas opposed such a requirement, commenting this 
should be a case-by-case decision based on risk reduction.
    9. Paiute and Southwest Gas reported their conclusion that the 
existing requirements in Sec.  192.179 are adequate. The companies 
recommended that operators have the flexibility to evaluate and 
determine where remote or automatic valves would be beneficial. They 
noted that Sec.  192.935 requires the consideration of additional 
valves as a preventive and mitigative measure and industry studies 
indicate little or no safety benefit to installing additional remote or 
automatic valves.
    10. The Texas Pipeline Association and Texas Oil & Gas Association 
opposed consideration of a requirement that all block valves be 
remotely-operable. The associations noted that it would be tremendously 
expensive to do so, and it would require power and communication 
sources that may not be readily available at valve sites.
    11. The California Public Utilities Commission commented that this 
could be impractical for distribution systems considering space 
limitations and the practicability of supplying communication 
facilities for valves. This issue is under review by the State for 
transmission facilities.
    12. The Iowa Utilities Board noted that remotely-operated valves 
require a SCADA or other type of remote monitoring and operating 
system. A requirement that all sectionalizing valves be remotely-
operable would thus be a de facto requirement that all operators, 
regardless of size or the potential consequences of an accident, 
install a SCADA system. Small operators and municipal utilities in Iowa 
do not have such systems.
    13. The Commissioners of Wyoming County Pennsylvania commented that 
it might be desirable for all valves to be remotely-operable or 
automatic, but PHMSA must consider what is reasonable and adequate.
    14. An anonymous commenter opposed consideration of a requirement 
that all valves be remotely-operable, noting that most gas pipeline 
accident consequences occur immediately upon release, before a remote 
valve could have any effect.
    H.7. Should PHMSA strengthen existing requirements by adding 
prescriptive decision criteria for operator evaluation of additional 
valves, remote closure, and/or valve automation? Should PHMSA set 
specific guidelines for valve locations in or around HCAs? If so, what 
should they be?
    1. INGAA and a number of pipeline operators opposed PHMSA's 
establishment of prescriptive criteria, suggesting instead that PHMSA 
develop guidance for Incident Mitigation Management.
    2. AGA, GPTC, and a number of pipeline operators commented that 
requirements in Sec.  192.179 are adequate. AGA noted that operators 
already consider additional valves in their emergency response 
portfolio and install them where economically, technically, and 
operationally feasible. Some operators noted that numerous industry 
studies indicate that there is little or no safety benefit to 
installing additional remote or automatic valves and Sec.  192.935 
already requires the consideration of additional valves as a preventive 
and mitigative measure.
    3. Accufacts supported the consideration of prescriptive criteria, 
arguing that prescriptive regulation should be mandated for certain gas 
transmission pipelines in HCAs, especially larger-diameter pipelines in 
certain areas where manual closure times can be long.
    4. Ameren Illinois opposed additional prescriptive criteria, 
arguing that existing requirements are sufficient and that additional 
valves should be considered when economically, technically, and 
operationally feasible to address specific safety concerns.
    5. California Public Utilities Commission expressed its conclusion 
that prescriptive decision criteria may need to be added for all Method 
1 HCA locations.
    6. The Iowa Utilities Board, the Texas Pipeline Association and the 
Texas Oil & Gas Association questioned whether it is possible to write 
prescriptive decision criteria that can reasonably address all possible 
situations and circumstances or always provide the best option. These 
commenters suggested that operator judgment and discretion should play 
a part in these decisions.
    7. MidAmerican expressed its belief that pipeline safety would not 
be enhanced by additional prescriptive criteria and opposed specific 
requirements for valve location near HCAs, noting that ASME/ANSI B31.8 
provides considerations for operators to take into account when 
deciding on valve locations.
    8. An anonymous commenter suggested that prescriptive criteria 
could be useful in assuring a degree of consistency among pipeline 
operators.
    H.8. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to the commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.
Response to Topic H Comments
    PHMSA appreciates the information provided by the commenters. Based 
on the investigation of the San Bruno incident, the NTSB recommended 
(P-11-11) that PHMSA promulgate regulations to explicitly require that 
automatic shutoff valves or remote control valves in high consequence 
areas and in Class 3 and 4 locations be installed and spaced at 
intervals considering the population factors listed in the regulations. 
In addition, Section 4 of the Act requires issuance of regulations on 
the use of automatic or remote-controlled shut-off valves, or 
equivalent technology, if appropriate, and where economically, 
technically, and operationally feasible. The Act also requires the 
Comptroller General of the United States to complete a study on the 
ability of transmission pipeline facility operators to respond to a 
hazardous liquid or gas release from a pipeline segment located in a 
high-consequence area. On March 27, 2012, PHMSA sponsored a public 
workshop to seek stakeholder input on this issue. On October 5, 2012, 
PHMSA also briefed stakeholders, via a webcast, on the status of an 
ongoing study conducted by Oak Ridge National Laboratory on 
understanding the application of automatic control and remote control 
shutoff valves. The final study was published in December 2012. PHMSA 
also included this topic in the July 18, 2012 Pipeline Research Forum. 
PHMSA will take further action on this topic after completion of the 
assessment of the findings from these activities. PHMSA will consider 
the comments

[[Page 20781]]

received on the ANPRM and will consider this topic in future 
rulemaking, as required.

I. Corrosion Control

    Gas transmission pipelines are generally constructed of steel pipe, 
and corrosion is a potential threat. Subpart I of part 192 addresses 
the requirements for corrosion control of gas transmission pipelines, 
including the requirements related to external corrosion, internal 
corrosion, and atmospheric corrosion. However, this subpart does not 
include requirements for the specific threat of Stress Corrosion 
Cracking (SCC). The ANPRM requested comments regarding revisions to 
subpart I to improve the specificity of existing requirements and to 
add requirements relative to SCC.
    Existing requirements have proven effective in reducing the 
occurrence of incidents caused by external corrosion. Many of the 
provisions in subpart I, however, are general in nature. In addition, 
the current regulations do not include provisions that address issues 
that experience has shown are important to protecting pipelines from 
corrosion damage, including:
     Post-construction surveys for coating damage.
     Post-construction close interval survey (CIS) to assess 
the adequacy of cathodic protection (CP) and inform the location of CP 
test stations.
     Periodic interference current surveys to detect and 
address electrical currents that could reduce the effectiveness of CP.
     Periodic use of cleaning pigs or sampling of accumulated 
liquids to assure that internal corrosion is not occurring.
    Corrosion control regulations applicable to gas transmission 
pipelines currently do not include requirements relative to SCC. SCC is 
cracking induced from the combined influence of tensile stress and a 
corrosive medium. SCC has caused numerous pipeline failures on 
hazardous liquids pipelines, including a 2003 failure on a Kinder 
Morgan pipeline in Arizona, a 2004 failure on an Explorer Pipeline 
Company pipeline in Oklahoma, a 2005 failure on an Enterprise Products 
Operating line in Missouri, and a 2008 failure on an Oneok NGL Pipeline 
in Iowa. More effective methods of preventing, detecting, assessing and 
remediating SCC in pipelines are important to making further reductions 
in pipeline failures.
    The ANPRM then listed questions for consideration and comment. The 
following are general comments received related to the topic as well as 
comments related to the specific questions:
General Comments for Topic I
    1. AGA opined that the questions posed under this topic are unclear 
and disjointed and do not differentiate between distribution and 
transmission pipelines. In addition, AGA stated that PHMSA did not 
provide a rationale for why there is any concern over subpart I. A 
number of pipeline operators supported AGA's comments.
    2. MidAmerican noted that PHMSA says current requirements are 
adequate yet goes on to propose new requirements.
    3. INGAA reported that its members commit to mitigating corrosion 
anomalies in accordance with ASME/ANSI B31.8S, both inside and outside 
HCAs. INGAA argued that enhanced external corrosion management methods, 
such as close interval surveys and post-construction coating surveys, 
should not be required singularly and arbitrarily by new prescriptive 
regulations, since these methods can be redundant or inferior when 
combined with other assessment techniques. INGAA argued that these 
methods should continue to be used by operators on a threat-specific 
basis, as is currently practiced under performance-based regulations 
and consensus-based IM programs. A number of pipeline operators 
supported INGAA's comments.
    4. Chevron argued that more prescriptive requirements are 
unnecessary, noting that current regulations allow operators the 
flexibility to select the most effective corrosion control method for 
the specific corrosion threats to a pipeline segment.
    5. MidAmerican reported that it has never identified internal 
corrosion on its pipeline system and prescriptive requirements related 
to that threat would divert resources. MidAmerican opined that subpart 
I provides an adequate level of safety and any changes in that subpart 
should be approached carefully because they could be beneficial or 
detrimental for reducing risk. MidAmerican further noted that NACE 
SP0204 and ASME/ANSI B31.8S provide adequate guidance in this area.
    6. TransCanada suggested that PHMSA incorporate the new SCC 
management provision in ASME/ANSI B31.8S as the basis for identifying 
and mitigating SCC and be responsive to further enhancements. 
TransCanada also suggested that the best way to manage corrosion 
anomalies is through assessments.
    7. Dominion East Ohio opined that existing regulations in this area 
are adequate.
    8. NAPSR urged PHMSA to establish or adopt standards or procedures, 
through a rulemaking proceeding, for improving the methods of 
preventing, detecting, assessing, and remediating stress corrosion 
cracking. NAPSR also suggested that PHMSA consider additional 
requirements to perform periodic coating surveys at compressor 
discharges and other high-temperature areas potentially susceptible to 
SCC and develop a training module for pipeline operators and federal 
and state inspectors that would include the identification of potential 
areas of SCC, detecting, assessing and remediating SCC.
    9. A private citizen reported that his analysis of data from over 
5000 lightning strikes indicates that cathodic protection systems make 
pipelines a frequent target for lightning.
    10. A private citizen suggested that enforcement of cathodic 
protection requirements be strengthened, stating that the number of 
enforcement actions indicates that operators are not operating or 
maintaining CP as required.
    11. A private citizen suggested that in-line inspection (ILI) 
capable of detecting seam issues should be required for pipe 
susceptible to selective seam weld corrosion, since pressure testing is 
not adequate to detect non-leak anomalies. If not possible, the 
commenter would require that this pipe be replaced.
Response
    PHMSA appreciates the information provided by the commenters. In 
light of the contributing factors to the San Bruno incident, including 
PG&E's reliance on direct assessment under circumstances for which 
direct assessment was not effective, and the incident in Marshall, 
Michigan, where fracture features were consistent with stress corrosion 
cracking, PHMSA believes that more specific measures are needed to 
address both stress corrosion cracking and selective seam weld 
corrosion. Based on lessons learned from incident investigations, such 
as the 2012 incident in Sissonville, West Virginia and the 2007 
incident in Delhi, Louisiana, and improved capabilities of corrosion 
evaluation tools and methods, PHMSA believes that more specific minimum 
requirements are needed for control of both internal and external 
corrosion. In addition, cathodic protection is a well-established 
corrosion control tool, and PHMSA believes the benefits of cathodic 
protection outweigh any potential risks. Therefore, PHMSA proposes 
several

[[Page 20782]]

enhancements to subpart I for corrosion control and subparts M and O 
for assessment, including specific requirements to address stress 
corrosion cracking and selective seam weld corrosion, and enhanced 
corrosion control measures for HCAs, which are discussed in more detail 
in response to specific questions, below.
Comments Submitted for Questions in Topic I
    I.1. Should PHMSA revise subpart I to provide additional 
specificity to requirements that are now presented in general terms? If 
so, which sections should be revised? What standards exist from which 
to draw more specific requirements?
    1. INGAA and a number of pipeline operators commented that adding 
prescriptive requirements would be disruptive to operators, noting 
PHMSA has acknowledged the effectiveness of performance-based elements 
of the current requirements.
    2. The AGA, the GPTC, the Texas Pipeline Association, the Texas Oil 
& Gas Association, and numerous pipeline operators questioned the need 
to amend subpart I. AGA noted that this is one of the more prescriptive 
sections of the code and has a 40-year history of demonstrated 
effectiveness.
    3. Ameren Illinois opined it is not necessary to revise subpart I, 
because integrity management regulations require operators to identify 
threats and to manage them.
    4. MidAmerican opposed more specific requirements for corrosion 
control, noting that there is wide diversity among pipelines and it is 
unlikely that a single set of specific requirements would apply 
effectively to all pipelines. MidAmerican suggested that additional 
specific requirements must be tailored to a wide range of pipeline 
configurations to be of any value.
    5. Northern Natural Gas reported that IM results demonstrate that 
corrosion has been adequately addressed on its pipeline system.
    6. Paiute and Southwest Gas noted that subpart I is one of the most 
prescriptive sections of the code, subpart O provides an additional 
layer of regulation, and NACE standards are robust and incorporated by 
reference.
    7. Panhandle Energy commented that existing performance based 
regulations require the pipeline operator to establish procedures to 
determine the adequacy of CP monitoring locations and appropriate 
remediation schedules based on circumstances that are unique to each 
pipeline. Panhandle observed that PHMSA appears to be attempting to 
establish ``One Size Fits All'' prescriptive requirements and opined 
that such changes would have no positive effect on safety and may be 
detrimental.
    8. Accufacts observed that too many pipeline operators are assuming 
that IM assessments can replace subpart I requirements when the intent 
was that the regulations work in conjunction with one another. 
Accufacts suggested that prescriptive regulation is needed to avoid 
serious misapplication of the IM section and to assure that subpart I 
regulations are implemented to keep corrosion under control.
    9. Panhandle observed that the ANPRM states that ``prompt'' as used 
in Sec.  192.465(d) is not defined, and does not recognize the 
definition of ``prompt remedial action'' outlined in the 1989 Office of 
Pipeline Safety's Operation and Enforcement Manual. Panhandle noted 
that the enforcement guidance requires PHMSA to evaluate the 
circumstances and provide rationale for any determination of 
``unreasonable delay'' in any enforcement action associated with Sec.  
192.465(d). Panhandle observed that such evaluations are inherent in 
the enforcement of performance-based regulations and stand in sharp 
contrast to the ``check-box'' enforcement mentality of prescriptive 
regulations. Panhandle complained that the language of the ANPRM 
contradicts more than 20 years of enforcement history. Panhandle 
interpreted the ANPRM to mean that PHMSA has no authority to interpret 
part 192 other than through rulemaking.
    10. An anonymous commenter suggested that PHMSA delete the 
requirement regarding 300 mV pipe-to-soil reading shift and adopt NACE 
SP0169.
    11. The California Public Utilities Commission suggested that PHMSA 
consider modifying acceptance criteria to be based on instant-off 
readings, arguing that this would provide improved specificity 
concerning IR drop.
Response to Question I.1 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of industry comments do not support revising subpart I to 
provide additional specificity to requirements. However, for the 
reasons discussed in this NPRM, PHMSA believes that certain regulations 
can be improved to better address issues that experience has shown can 
be important to protecting pipelines from corrosion damage, and that 
prudent operators currently implement. Therefore, PHMSA proposes to 
amend subparts G and I to: (1) Enhance requirements for electrical 
surveys (i.e., close interval surveys); (2) require post construction 
surveys for coating damage; (3) require interference current surveys; 
(4) add more explicit requirements for internal corrosion control; and 
(5) revise Appendix D to better align with the criteria for cathodic 
protection in NACE SP0169. Included in these changes is a new 
definition of the terms ``electrical survey'' and ``close interval 
survey.'' To conform to the revised definition of ``electrical 
survey,'' the use of that term in subpart O would be replaced with 
``indirect assessment'' to accommodate other techniques in addition to 
close-interval surveys.
    I.2. Should PHMSA prescribe additional requirements for post-
construction surveys for coating damage or to determine the adequacy of 
CP? If so, what factors should be addressed e.g., pipeline operating 
temperatures, coating types, etc.)?
    1. INGAA and a number of pipeline operators argued that post-
construction surveys are of limited use, arguing that they can identify 
damaged coating but not necessarily areas where SCC can occur.
    2. AGA, supported by a number of its pipeline operator members, 
opined that existing requirements for post-construction surveys for 
coating damage and cathodic protection are sufficient and operators 
need flexibility to apply their resources to the highest risk areas.
    3. GPTC agreed that existing regulations are sufficient, noting 
that operators are not experiencing difficulties related to post-
construction surveys for coating damage or for determining the adequacy 
of CP.
    4. Ameren Illinois noted that part 192 requirements are followed 
for the installation of new coated steel pipe and it will develop a 
process to deal with any problems that may be identified through 
integrity management. Atmos agreed, noting that post-construction 
baseline surveys are typically performed.
    5. Kern River opined that corrosion control measures and mitigation 
are site specific and therefore universal conditions and mitigation 
requirements would likely be ineffective and inefficient. Performance-
based criteria are the best way to ensure the integrity of the pipeline 
with the most innovative and effective solutions.
    6. MidAmerican opposed new requirements, noting that areas of 
coating damage on pipelines are protected from corrosion by cathodic 
protection and existing requirements are adequate in this area.
    7. NACE concluded that current regulations have proven adequate and

[[Page 20783]]

noted that PHMSA acknowledges in the ANPRM that ``[T]hese requirements 
have proven effective in minimizing the occurrence of incidents caused 
by gas transmission pipeline corrosion.''
    8. Paiute and Southwest Gas opined that current requirements for 
coatings (Sec.  192.461) and cathodic protection (Sec.  192.463) are 
sufficient.
    9. Northern Natural Gas stated that no new requirements are needed, 
observing that it takes action when CP surveys indicate a concern.
    10. Panhandle argued that the proposed requirement for post 
construction coating does not address the cause of coating damage 
during construction and INGAA best practices have proven to be an 
effective means to provide pipeline safety, affording flexibility and 
recognizing the inherent limitations of coating surveys. Panhandle 
observed that PHMSA's requirements for the investigation of anomalies 
found during post construction coating surveys on alternate MAOP lines 
are overly conservative, waste resources, do not enhance pipeline 
safety, and should not be considered for use in any proposed 
rulemaking. Panhandle further recommended that any proposed regulations 
related to pipeline temperature should not use the 120 degrees 
Fahrenheit value used in Sec.  192.620, since studies have demonstrated 
pipeline coatings can withstand temperatures up to 150 degrees. 
Panhandle further argued that industry experience verifies that the 
vast majority of coating holidays associated with pipeline construction 
are not an integrity threat when cathodic protection is applied to the 
pipeline. It also suggested that verification of pipeline integrity 
through ILI or pressure testing better utilizes resources than 
excavation and repair of pinholes in pipeline coating systems.
    11. Panhandle observed that, from its experience with over 900 
completed excavations, the coating anomaly ranking system of NACE 
SP0502 is extremely conservative and should only be used as part of the 
ECDA process.
    12. Texas Pipeline Association and Texas Oil & Gas Association 
suggested that PHMSA should consider requiring close interval surveys 
at 5-year intervals.
    13. TransCanada noted that enhanced external corrosion management 
methods, such as close interval surveys and post construction coating 
surveys, have proven effective in helping identify and mitigate certain 
corrosion damage conditions. TransCanada argued, however, that these 
methods should not be required singularly and arbitrarily by new 
prescriptive requirements, as they can be redundant or inferior when 
combined with other assessment techniques.
    14. Pipeline Safety Trust suggested that additional post-
construction surveying should be required to identify damage to or 
weakness in coating and to ensure the integrity of CP.
    15. An anonymous commenter suggested that PHMSA require close 
interval survey before energizing new CP components, after backfill has 
settled, noting that this would ensure test stations are located in 
areas that will assure adequate protection.
    16. The Commissioners of Wyoming County Pennsylvania recommended 
that PHMSA review operator practices and codify the ``best practices'' 
in this area.
Response to Question I.2 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of industry comments do not support revising subpart I to 
prescribe additional requirements for post-construction surveys for 
coating damage or to determine the adequacy of CP. However, as detailed 
in the ANPRM, experience has shown that construction activities can 
damage coating and that identifying and remediating this damage can 
help protect pipeline integrity. PHMSA does agree that prescriptive 
practices for conducting coating surveys, as well as the criteria for 
remediation and other responses to indications of coating damage, are 
not always appropriate because coating damage is case-specific. 
Therefore, PHMSA proposes to add a requirement that each coating be 
assessed to ensure integrity of the coating using direct current 
voltage gradient (DCVG) or alternating current voltage gradient (ACVG) 
and damage be remediated if damage is discovered. In addition, for HCA 
segments, PHMSA proposes enhanced preventive and mitigative measures 
and repair criteria for repair of coating with a voltage drop 
classified as moderate or severe.
    I.3. Should PHMSA require periodic interference current surveys? If 
so, to which pipelines should this requirement apply and what 
acceptance criteria should be used?
    1. INGAA and a number of pipeline operators recommended that PHMSA 
not establish new requirements in this area without discussing the 
topic with operators first. INGAA pointed out that guidance already 
exists in the form of Advisory Bulletin ADB-03-06 and NACE SP0169.
    2. Kern River opposed new requirements for periodic surveys, 
arguing that Sec. Sec.  192.465, 192.467, and 192.473 adequately 
address the concerns.
    3. Ameren Illinois also opposed new requirements. Ameren reported 
that it conducts testing annually at sites where stray currents are 
expected and noted that integrity management regulations already 
require operators to identify and address threats.
    4. NACE International suggested that current regulations are 
adequate and have served the public interest. NACE noted operators are 
currently taking action to identify interference currents and protect 
their pipelines, and it has provided guidance through standards and 
technical papers.
    5. Atmos noted that interference surveys would be a part of an 
investigation into cathodic protection systems that do not provide 
minimum levels of protection. Operators are already required to 
maintain minimum levels of protection.
    6. Northern Natural Gas reported that it conducts additional 
surveys when issues are discovered during periodic maintenance, when 
new foreign line crossing are installed, or for new construction, but 
opposed new requirements in this area.
    7. Paiute and Southwest Gas opposed new requirements, noting that 
operators should have the flexibility to allocate their resources in a 
manner that best suits their system.
    8. Panhandle opposed new requirements, noting that existing 
performance-based regulations have proven adequate to address the 
threat of stray currents. Panhandle commented that the gas pipeline 
industry recognized and reacted to the threat of AC interference 
decades prior to the ANPRM, and suggested that the lack of 
justification from PHMSA on this issue is a strong indicator that 
industry has reacted appropriately to integrity threats in accordance 
with the requirements of Sec.  192.473. Panhandle noted that 
interference currents have been addressed in several industry standards 
and publications. In particular, Section 9, Control of Interference 
Currents, of NACE SP0169, Control of External Corrosion on Underground 
of Submerged Metallic Piping Systems, provides guidance for the 
detection and mitigation of interference currents.
    9. Texas Pipeline Association and Texas Oil & Gas Association 
stated that current regulations are sufficient; however, if new 
regulations are promulgated, the associations recommended that PHMSA 
use the liquid pipeline requirement for periodic interference surveys 
and be applicable only to foreign line crossings and

[[Page 20784]]

pipelines near large DC-powered equipment.
    10. An anonymous commenter stated that new regulations are not 
needed, as most operators will conduct surveys on their own, generally 
when pipe-to-soil readings drop.
Response to Question I.3 Comments
    PHMSA appreciates the information provided by the commenters. 
Industry comments do not support revising subpart I to require periodic 
interference current surveys. However, as detailed in the ANPRM, 
pipelines are often routed near, in parallel with, or in common rights-
of-way with, electrical transmission lines or other pipelines that can 
induce interference currents, which, in turn, can induce corrosion. 
Recent incidents on pipelines operated by Kern River and Center Point 
are examples of incidents this requirement seeks to prevent. Section 
192.473 currently requires that operators of pipelines subject to stray 
currents have a program to minimize detrimental effects but does not 
require surveys, mitigation, or provide any criteria for determining 
the adequacy of such programs. Therefore, PHMSA proposes to add a 
requirement that the continuing program to minimize the detrimental 
effects of stray currents must include: (1) Interference surveys to 
detect the presence and level of any electrical current that could 
impact external corrosion where interference is suspected; (2) analysis 
of the results of the survey; and (3) prompt remediation of problems 
after completing the survey to protect the pipeline segment from 
deleterious current. For HCA segments, PHMSA proposes to address this 
in enhanced preventive and mitigative measures, and to include 
performance criteria.
    I.4. Should PHMSA require additional measures to prevent internal 
corrosion in gas transmission pipelines? If so, what measures should be 
required?
    1. INGAA, AGA, GPTC, and numerous pipeline operators contended that 
existing requirements are adequate to manage internal corrosion. INGAA 
noted that subparts I and O include requirements for controlling 
internal corrosion and assessments are being performed on almost all 
gas transmission lines. INGAA further commented that controlling gas 
quality is most important.
    2. Ameren Illinois opposed new requirements addressing internal 
corrosion, noting that Sec.  192.475 addresses the topic and subpart O 
requires operators to respond to risks that are identified.
    3. Kern River and Northern Natural Gas opposed new requirements, 
noting that industry data show IC is a minor threat to natural gas 
transmission pipelines. Kern River commented that ASME/ANSI B31.8S, 
Appendix A2, covers the analysis of gas constituents. Northern monitors 
gas quality and takes corrective action as needed.
    4. MidAmerican opposed new requirements, commenting that internal 
corrosion is a regional problem and does not occur in many areas of the 
country. MidAmerican requested that current integrity management 
regulations be revised to eliminate the need to conduct internal 
corrosion direct assessment when internal corrosion is not a threat.
    5. NACE International opined that current regulations in subpart I 
are adequate to address internal corrosion, and PHMSA's proposed 
prescriptive requirements are not feasible.
    6. Panhandle observed that requirements to minimize the potential 
for internal corrosion in gas transmission pipelines are included in 
Sec. Sec.  192.475, 192.476, and 192.477. In addition, OPS issued ADB-
00-02 requiring pipeline operators to review their internal corrosion 
monitoring programs and operation. IM regulations in subpart O require 
integrity management assessments that address the threat of internal 
corrosion. INGAA members report that completion of baseline assessments 
required by subpart O will result in the assessment of more than half 
of the gas transmission pipeline mileage in the U.S. Panhandle 
commented that several proposed prescriptive internal corrosion 
requirements provided in the ANPRM are not feasible and noted that 
liquids tend to accumulate in low spots that typically are not 
accessible for sampling. Panhandle opined that vigilant enforcement of 
gas quality standards is the most essential component of an internal 
corrosion control program.
    7. Texas Pipeline Association and Texas Oil & Gas Association 
argued that no benefit would be gained by additional requirements in 
this area. The associations observed that internal corrosion threats 
are highly localized and monitoring and remediation efforts must be 
customized for local conditions.
    8. IUB noted that not all pipelines are susceptible to internal 
corrosion and commented that operators and state inspection personnel 
should not be unduly burdened by additional measures when problems do 
not exist.
    9. An anonymous commenter suggested that PHMSA require each 
operator to have a subject matter expert well qualified in internal 
corrosion, arguing that most operators currently rely on third-party 
contractors.
Response to Question I.4 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of industry comments do not support revising subpart I to 
require additional measures to prevent internal corrosion in gas 
transmission pipelines. However, the current requirements for internal 
corrosion control are non-specific and PHMSA believes that there is 
benefit in enhancing the current internal corrosion control 
requirements to establish a more effective minimum standard for 
internal corrosion management. Therefore, PHMSA proposes to add a 
requirement that each operator develop and implement a program to 
monitor for and mitigate the presence of, deleterious gas stream 
constituents and that the program be reviewed at least semi-annually. 
For HCA segments, PHMSA proposes to address this in enhanced preventive 
and mitigative measures to include objective performance criteria.
    I.5. Should PHMSA prescribe practices or standards that address 
prevention, detection, assessment, and remediation of SCC on gas 
transmission pipeline systems? Should PHMSA require additional surveys 
or shorter IM survey internals based upon the pipeline operating 
temperatures and coating types?
    1. INGAA and a number of pipeline operators recommended that PHMSA 
avoid prescriptive requirements for the prevention, detection, 
assessment, and remediation of SCC. The commenters noted that SCC 
varies from pipeline to pipeline and suggested that threat management 
should be through a framework of processes and decision making that can 
tailor threat management to the requirements of each pipeline.
    2. AGA and a number of its pipeline operators also objected to new 
requirements in this area, noting that numerous industry documents 
exist that provide guidance to address SCC.
    3. Panhandle suggested that PHMSA avoid prescriptive standards for 
the prevention, detection, assessment, and remediation of SCC on gas 
transmission systems given the complex and variable nature of the 
factors contributing to the formation and growth of SCC, arguing 
performance-based standards allow operators the maximum flexibility to 
develop and apply situational techniques for detecting, assessing, and 
remediating this threat. Panhandle noted that multiple standards and 
publications are available to address internal corrosion and that the 
Pipeline

[[Page 20785]]

Research Council International (PRCI) has ongoing research in this 
area. Panhandle expressed the view that voluntary use of performance 
based standards, allowing operator flexibility in detecting, assessing 
and remediating this threat, will ensure that the methods used in 
managing these types of anomalies continue to improve.
    4. GPTC, Ameren Illinois, Atmos, Paiute, and Southwest Gas argued 
that existing regulations are sufficient and noted that there are 
numerous industry documents that provide additional guidance for 
addressing SCC.
    5. TransCanada suggested that PHMSA adopt the current version of 
ASME/ANSI B31.8S.
    6. The Commissioners of Wyoming County Pennsylvania opined that it 
is reasonable for PHMSA to prescribe practices or standards that 
address prevention, detection, assessment and remediation of SCC on 
transmission and gas gathering lines, including those in Class 1 
locations. The Commissioners argued that it is important to address 
this aspect of corrosion given aging of existing pipelines and the 
significant number of new pipelines.
    7. Air Products and Chemicals argued that operators should not be 
required to undertake SCC prevention, detection, assessment and 
remediation activities where a pipeline does not meet the B31.8S 
criterion for SCC. Air Products further commented that it is important 
that PHMSA's regulations and standards reflect the threshold concept of 
susceptibility to SCC, and that a pipeline that does not meet the 
B31.8S criteria for SCC risk should not be required to undertake SCC 
prevention, detection, assessment, and remediation activities.
    8. NACE International stated that overly prescriptive rules can 
supplant sound engineering judgment and prevent innovation and the 
development of new technologies.
    9. Northern Natural Gas argued that the current regulations and 
industry standards provide adequate guidance and that the assessment 
criteria address operating temperature and coating type. Northern 
Natural Gas noted that operating temperature is addressed in PHMSA Gas 
FAQ 223 and that the reassessment interval should be determined by the 
results of the integrity assessment performed pursuant to ASME B31.8S.
    10. MidAmerican pointed out that these concerns are addressed in 
the pre-assessment phase of direct assessment and adequately covered in 
ASME/ANSI B31.8S.
    11. Texas Pipeline Association and Texas Oil & Gas Association 
suggested that additional regulations related to SCC could prove 
beneficial. At the same time, the associations recommended that PHMSA 
not require additional surveys or shorter intervals, arguing that the 
current regulations are based on sound engineering practices.
    12. A private citizen commented that SCC should be addressed as 
part of a comprehensive corrosion control program.
    13. An anonymous commenter noted that a reliable survey technique 
for SCC does not now exist and suggested that PHMSA require shorter 
assessment intervals for pipelines with a history of SCC.
    14. INGAA argued that pipe temperature and coating are not 
sufficient to identify SCC. INGAA contended that ASME/ANSI B31.8S 
adequately covers prevention, detection, assessments, and remediation 
of SCC and criteria to capture all pipe potentially susceptible to SCC 
would be overly conservative. A number of pipeline operators supported 
INGAA's comments.
    15. NACE International opined that there are too many factors 
involved, and they are too interrelated and location-specific, to allow 
prescribing an optimal assessment interval for SCC.
Response to Question I.5 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of industry comments do not support new requirements for the 
prevention, detection, assessment, and remediation of SCC. PHMSA 
recognizes that SCC is an important safety concern, but does not 
believe the current methods for managing SCC anomalies supports 
prescribing a detailed SCC management approach that would be effective 
for all operators. PHMSA does not propose to amend subpart I to 
prescribe an SCC management plan at this time. PHMSA will continue to 
study this issue and support ongoing research. PHMSA plans to hold a 
public forum on the development of SCC standards in the future. Once 
that process is complete, PHMSA will consider new minimum safety 
standards for managing the threat of SCC. However, under topics C and 
G, above, PHMSA does propose to include more specific requirements for 
conducting integrity assessments for the threat of SCC and for 
enhancing the HCA and non-HCA repair criteria to address SCC.
    I.6. Does the NACE SP0204-2008 (formerly RP0204) Standard ``Stress 
Corrosion Cracking Direct Assessment Methodology'' address the full 
life cycle concerns associated with SCC? Should PHMSA consider this, or 
any other standards to govern the SCC assessment and remediation 
procedures? Do these standards vary significantly from existing 
practices associated with SCC assessments?
    1. INGAA and a number of pipeline operators stated that NACE SP0204 
does not address the full life cycle of concerns of SCC. INGAA added 
that SP0204, along with ASME/ANSI B31.8S, NACE publication 35103, STP-
TP-011, and Canadian recommended practices, do cover the full life 
cycle concerns.
    2. NACE International reported that its standard (SP0204) does not 
address the full life cycle concerns of SCC.
    3. GPTC noted that existing regulations and standards address SCC 
concerns and commented that it is not clear what is meant by ``full 
life cycle concerns.''
    4. Ameren Illinois argued that full life cycle concerns are 
addressed in the pre-assessment phase of stress corrosion cracking 
direct assessment (SCCDA) and new prescriptive requirements are not 
needed.
    5. Northern Natural Gas commented that ASME/ANSI B31.8S should be 
used in conjunction with NACE SP0204.
    6. Panhandle reported that SCCDA was never intended to address full 
life cycle management for SCC. The standard does not address aspects 
such as the formation or nucleation of cracks or calculations to assess 
the severity of cracks. Panhandle opined that the collective body of 
SCC research does address the full life cycle, but cautioned the full 
body of knowledge of all documents must be considered as some may be 
dated and do not reflect current knowledge on SCC management.
    7. An anonymous commenter suggested that NACE SP0204 does not 
address full life cycle concerns, noting that SCC has been found in 
circumstances where the standard would suggest it should not be 
expected.
Response to Question I.6 Comments
    PHMSA appreciates the information provided by the commenters and 
agrees that sufficient information is not available at this time to 
specify prescriptive standards for SCC management. See the response to 
comments received on question I.5.
    I.7. Are there statistics available on the extent to which the 
application of the NACE Standard, or other standards, have affected the 
number of SCC indications operators have detected on their pipelines 
and the number of SCC-related pipeline failures? Are statistics 
available that identify the number of SCC occurrences that have been

[[Page 20786]]

discovered at locations that meet the screening criteria in the NACE 
standard and at locations that do not meet the screening criteria?
    1. INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas 
Association, and numerous pipeline operators reported that no data has 
been collected on the application of any current standard. INGAA added 
that available statistics indicate that the annual number of failures 
due to SCC is generally decreasing and noted that a high percentage of 
in-service failures, failures during hydro testing, and instances where 
SCC cracks greater than 10 percent were found during excavations have 
met the screening criteria of ASME/ANSI B31.8S (which are identical to 
the NACE criteria).
    2. Northern Natural Gas reported that it has found one instance of 
SCC and no segments were identified subject to similar circumstances.
Response to Question I.7 Comments
    PHMSA appreciates the information provided by the commenters and 
agrees that sufficient information is not available at this time to 
specify prescriptive standards for SCC management. PHMSA will be 
studying this issue and soliciting further input from stakeholders in 
the future. See the response to comments received on question I.5.
    I.8. If new standards were to be developed for SCC, what key issues 
should they address? Should they be voluntary?
    1. NACE International suggested that existing standards should be 
updated and improved rather than developing new standards, noting that 
such updating is as normal part of the standards process.
    2. INGAA and a number of its pipeline operators supported the 
development of voluntary standards to cover detection, assessment, 
mitigation, periodic assessment, and evaluation of effectiveness.
    3. Panhandle supported the development of industry standards to 
manage SCC but does not believe that such a document can be completed 
until the gaps in the understanding of SCC have been addressed.
    4. GPTC, Ameren Illinois, and Northern Natural Gas opined that the 
combination of ASME/ANSI B31.8S and ASME STP-PT-011 provide adequate 
guidance.
    5. Atmos recommended that further investigation be required if SCC 
outside of the criterion specified in NACE SP0204-2008 is found. Atmos 
stated that any new standards that are developed should be voluntary so 
that operators have additional methodologies available for mitigating 
the threat of SCC as currently required by Sec.  192.929.
    6. Texas Pipeline Association and Texas Oil & Gas Association 
recommended any new standards for SCC apply only to Class 1 locations, 
based on their conclusion that pipe designed for Class 2 conditions 
(and above) is not susceptible to SCC.
Response to Question I.8 Comments
    PHMSA appreciates the information provided by the commenters and 
agrees that sufficient information is not available at this time to 
specify prescriptive standards for SCC management. PHMSA will be 
studying this issue and soliciting further input from stakeholders in 
the future. See the response to comments received on question I.5.
    I.9. Does the definition of corrosive gas need to clarify that 
other constituents of a gas stream (e.g., water, carbon dioxide, sulfur 
and hydrogen sulfide) could make the gas stream corrosive? If so, why 
does it need to be clarified?
    1. INGAA, supported by a number of its pipeline operators, opined 
that the existing regulations are adequate, and commented that 
prescriptive limits, such as those in Sec.  192.620, would not be as 
effective in reducing the potential for internal corrosion.
    2. GPTC recommended that Sec.  192.476 be revised to reflect only 
those liquids that act as an electrolyte (i.e., water).
    3. AGA sees no need to clarify the definition and noted that the 
stated constituents pose no threat if water is not present.
    4. Atmos, Paiute, and Southwest Gas noted that gas tariffs maintain 
gas quality and water must be present with the constituents listed to 
produce a corrosive gas stream. Paiute opined that Sec.  192.929 and 
ASME/ANSI B31.8S are sufficient.
    5. NACE International expressed uncertainty as to why the 
definition needs to be clarified. NACE also noted that there are more 
factors than those listed in the question that affect the corrosiveness 
of a gas stream.
    6. MidAmerican, Ameren Illinois, and Northern Natural Gas noted 
that ASME/ANSI B31.8S requires analysis of gas constituents and argued 
that operators know what constitutes a corrosive gas stream. The 
operators do not believe the definition needs to be changed.
    7. Kern River suggested that the definition should be changed, 
noting that water must be present, in addition to the listed 
constituents, to make a gas stream corrosive.
    8. Texas Pipeline Association and Texas Oil & Gas Association 
suggested no change to the definition is needed, since operators 
understand the listed constituents, when combined with water, can cause 
internal corrosion.
    9. An anonymous commenter suggested that PHMSA not attempt to list 
constituents that could make a gas stream corrosive, arguing there are 
too many scenarios to cover. The commenter noted that the issue is not 
simple: H2O w/o free O2, or CO2 or 
sulfur alone are not corrosive.
Response to Question I.9 Comments
    PHMSA appreciates the information provided by commenters, and 
consistent with the majority of comments, PHMSA does not propose to 
revise the definition of corrosive gas at this time. However, PHMSA 
does propose to clarify the regulations by listing examples of 
constituents that are potentially corrosive, and to propose objective 
performance criteria for monitoring gas stream contaminants for HCA 
segments.
    I.10. Should PHMSA prescribe for HCAs and non-HCAs external 
corrosion control survey timing intervals for close interval surveys 
that are used to determine the effectiveness of CP?
    1. INGAA, supported by a number of pipeline operators, suggested 
that safety would be best served by following a risk-based approach to 
determine intervals for corrosion control or close interval surveys, 
arguing that prescriptive requirements applicable to all pipelines 
would divert safety resources from other high-risk tasks.
    2. AGA, GPTC, and a number of pipeline operators argued that there 
is no reason for PHMSA to specify timing of close interval surveys, 
contending that the current subpart I requirements have proven to be 
successful and the use of CIS as an indirect assessment tool is built 
into NACE SP0502.
    3. Ameren Illinois opposed the prescribed intervals for close 
interval surveys, arguing that Sec.  192.463 and 192.465 are adequate. 
In addition, Ameren noted that Sec.  192.917(e)(5) requires an operator 
to evaluate and remediate corrosion in both covered and non-covered 
segments when corrosion is found.
    4. Atmos opposed required timing for close interval surveys, 
arguing that CIS is just one tool that can be used to determine the 
effectiveness of CP.
    5. MidAmerican expressed its conclusion that establishing required 
timing intervals for close interval surveys would not be beneficial. 
MidAmerican noted that specific pipeline characteristics need to be 
taken

[[Page 20787]]

into consideration in establishing inspection intervals.
    6. Paiute and Southwest Gas opposed required periodicity for close 
interval surveys, arguing that NACE SP0207 provides adequate guidance.
    7. Northern Natural Gas commented that PHMSA should not prescribe 
external corrosion control survey intervals for close interval surveys, 
noting that its integrity management program demonstrates that external 
corrosion is being managed effectively.
    8. Texas Pipeline Association and Texas Oil & Gas Association 
argued that industry experience demonstrates existing requirements are 
adequate.
    9. An anonymous commenter suggested that specified periodicity for 
close interval surveys could have benefit, especially where a history 
of external corrosion exists.
Response to Question I.10 Comments
    PHMSA appreciates the information provided by the commenters. 
Recent experience, including the December 2012 explosion near 
Sissonville, WV and the 2007 incident near Delhi, LA, underscores the 
need to be more attentive to external corrosion mitigation activities. 
PHMSA proposes to enhance the requirements of subpart I to require that 
operators conduct close-interval surveys if annual test station 
readings indicate that cathodic protection is below the level of 
protection required in subpart I, or to restore adequate corrosion 
control. For HCA segments, PHMSA proposes to address these requirements 
in enhanced preventive and mitigative measures, to include an objective 
timeframe for restoration of deficient cathodic protection.
    I.11. Should PHMSA prescribe for HCAs and non-HCAs corrosion 
control measures with clearly defined conditions and appropriate 
mitigation efforts? If so, why?
    1. INGAA stated it does not believe it is feasible to develop 
prescriptive measures that identify necessary and sufficient monitoring 
and mitigation efforts in all environments. A number of pipeline 
operators supported INGAA's comments.
    2. AGA and a number of its operator members expressed their 
conclusion that the requirements of subpart I are sufficient, noting 
that they address HCA and non HCA alike.
    3. GPTC commented that the question does not make clear why 
additional measures should be prescribed given that operators have been 
successfully mitigating corrosion deficiencies for many years.
    4. Ameren Illinois expressed its conclusion that the science of 
corrosion mitigation is sufficiently advanced and appropriate 
mitigation measures are well known. Atmos, Paiute, and Southwest Gas 
agreed, concluding that subpart I is sufficient when implemented 
properly by appropriately trained and qualified personnel.
    5. MidAmerican opposed new requirements, arguing that current 
regulations address all practical mitigation efforts.
    6. Texas Pipeline Association and Texas Oil & Gas Association 
suggested that more time should be allowed before additional 
prescriptive requirements on cathodic protection are considered, noting 
that corrosion leaks are trending downward.
    7. The Commissioners of Wyoming County Pennsylvania suggested that 
it is reasonable that PHMSA prescribe corrosion control measures for 
HCAs and non-HCAs with clearly defined conditions and appropriate 
mitigation efforts. They cited information from NACE indicating that 25 
percent of all accidents are caused by corrosion and these accidents 
account for 36 percent of all accident damage. The Commissioners noted 
that gathering lines in the Marcellus Shale area have diameters and 
pressures similar to transmission lines and should be subjected to the 
same requirements.
    8. An anonymous commenter recommended that PHMSA not prescribe 
specific measures.
Response to Question I.11 Comments
    PHMSA appreciates the comments provided, and consistent with the 
majority of comments, does not propose additional regulatory changes at 
this time, other than to prescribe measures to promptly restore 
cathodic protection, as discussed in the response to comments received 
for question I.10.
    PHMSA is interested in the extent to which operators have 
implemented Canadian Energy Pipeline Association (CEPA) SCC, 
Recommended Practices 2nd Edition, 2007, and what the results have 
been.
    I.12. Are there statistics available on the extent to which gas 
transmission pipeline operators apply the Canadian Energy Pipeline 
Association (CEPA) practices?
    I.13. Are there statistics available that compare the number of SCC 
indications detected and SCC-related failures between operators 
applying the CEPA practices and those applying other SCC standards or 
practices?
    1. INGAA reported that most major operators in North America have 
adopted threat management closely aligned to CEPA standards, but that 
no specific data exist that correlate the use of CEPA methods to 
anomaly detection. INGAA reported a Joint Industry Project (JIP) study 
that shows that applying NACE SP0204, ASME/ANSI B31.8S, CEPA, and other 
standards has led to a significant reduction in in-service failures. 
Numerous pipeline operators supported INGAA comments.
    2. AGA, supported by a number of its pipeline operator members, 
questioned why a discussion of CEPA standards was included in the 
ANPRM. AGA suggested that CEPA practices are well suited to Canadian 
infrastructure, but not necessarily applicable in the United States and 
noted that CEPA is not often discussed by Canadian members at AGA 
meetings.
    3. GPTC expressed that its membership has little knowledge of CEPA 
standards, commented that it is not clear what is meant by full life 
cycle concerns, and argued that existing standards and regulations 
adequately address SCC concerns. GPTC is not aware of any data 
correlating the efficacy of CEPA to other standards.
    4. Paiute and Southwest Gas reported that they have not implemented 
CEPA standards.
Response to Questions I.12 and I.13 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
acknowledges the comments provided on the use of the CEPA SCC 
Recommended Practice and will consider that standard in its study of 
comprehensive safety requirements for SCC.
    I.14. Do the CEPA practices address the full life cycle concerns 
associated with SCC? If not, which are not addressed?
    1. INGAA reported its conclusion that CEPA standards address full 
life cycle concerns for near-neutral SCC. Many management techniques in 
CEPA standards are also applicable to high-pH SCC, but the two are not 
identical. Several pipeline operators supported INGAA's comments.
    2. Texas Pipeline Association and Texas Oil & Gas Association 
expressed their conclusion that CEPA standards address the full life 
cycle concerns of SCC.
Response to Question I.14 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
acknowledges the comments provided on the use of the CEPA SCC 
Recommended Practice and will consider that standard in its study of

[[Page 20788]]

comprehensive safety requirements for SCC.
    I.15. Are there additional industry practices that address SCC?
    1. INGAA, supported by a number of its pipeline operator members, 
reported that there are no related European standards and Australia has 
a standard similar to ASME/ANSI B31.8S. INGAA noted that SCC failures 
of pipelines installed since 1980 are rare and observed that quality 
coating and cathodic protection are the most effective means of 
preventing SCC.
    2. GPTC stated that NACE SP0204 and 35103, ASME/ANSI B31.8S, and 
GPTC guide material address SCC. Paiute and Southwest Gas agreed that 
NACE standards and GPTC provide relevant guidance.
    3. AGA commented that it does not have the statistics available to 
advise whether or not additional requirements are needed to address SCC 
threats.
    4. Atmos, Texas Pipeline Association and Texas Oil & Gas 
Association reported that they have no knowledge of other SCC standards 
or practices.
    5. Northern Natural Gas cited ASME/ANSI B31.8S and ASME STP-PT-011.
Response to Question I.15 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
acknowledges the comments provided on the standards, and will consider 
these standards in its study of comprehensive safety requirements for 
SCC.
    I.16. Are there statistics available on the extent to which various 
tools and methods can accurately and reliably detect and determine the 
severity of SCC?
    1. INGAA noted that the measurement of ILI crack detection tool 
performance is an ongoing research activity, both within JIP Phase II 
and within the Pipeline Research Council International, which is 
actively supported by the tool vendors and the pipeline operators. 
Several issues regarding the acquisition and interpretation of 
information need to be standardized by the practitioners before a clear 
picture can emerge. The implications of tool tolerance on predicted 
failure pressure are being studied in the JIP Phase II.
    2. GPTC, Atmos, Paiute, Southwest Gas, and an anonymous commenter 
reported that they are unaware of any relevant statistics.
    3. Northern Natural Gas reported that it has used electro-magnetic 
acoustic transducer (EMAT) ILI with some success.
    4. Panhandle commented that magnetic particle inspection (MPI) is 
effective at locating surface-breaking linear indications, a subset of 
SCC. Furthermore, abrasive wheel grinding in conjunction with MPI is an 
effective method to size the length and depth of surface-breaking 
linear indications, limited by the amount of metal that can be removed 
from in-service pipelines. Panhandle noted that PRCI research indicates 
that laser UT techniques can effectively locate and size SCC, but this 
method is relatively new and Panhandle has no experience with its use. 
Panhandle also reported that the use of EMAT has yet to be acknowledged 
as a replacement for hydrostatic testing but it is being evaluated in 
Phase II of the SCC Joint Industry Project (JIP); results of the study 
will be used to determine the path forward for EMAT technology.
    5. Texas Pipeline Association and Texas Oil & Gas Association 
reported that they have no knowledge of relevant references other than 
the Baker study.
Response to Question I.16 Comments
    PHMSA appreciates the information provided by the commenters and 
will consider this information in its study of comprehensive safety 
requirements for SCC.
    I.17. Are tools or methods available to detect accurately and 
reliably the severity of SCC when it is associated with longitudinal 
pipe seams?
    1. INGAA and a number of pipeline operators noted that detecting 
SCC close to a longitudinal seam is difficult and even harder near a 
girth weld. INGAA commented that developing tools to reliably detect 
and assess SCC near longitudinal seams is a continuing challenge.
    2. GPTC reported that SCC tools are available; however, GPTC 
cautioned that the ability to accurately and reliably detect the 
severity of SCC associated with longitudinal seams is dependent on 
specific operating conditions.
    3. Atmos commented that it knows of no tools that can accurately 
detect and estimate the severity of SCC near a longitudinal seam.
    4. Paiute and Southwest Gas reported that tools are being developed 
but are, as of yet, not accurate at determining the severity of SCC 
associated with longitudinal seams.
    5. Northern Natural Gas reported that it has used electro-magnetic 
acoustic transducer (EMAT) ILI with some success. Panhandle added that 
difficulties in using EMAT are further complicated when cracking is 
associated with a longitudinal seam.
    6. Texas Pipeline Association and Texas Oil & Gas Association 
expressed their conclusion that the best methods to assess for SCC near 
longitudinal seams are pressure testing and EMAT, although they noted 
that some operators have had success with transverse flux ILI.
    7. An anonymous commenter reported that new ILI tools exist but 
that analysts are not yet consistent in using them.
Response to Question I.17 Comments
    PHMSA appreciates the information provided by the commenters and 
will consider this information in its study of comprehensive safety 
requirements for SCC.
    I.18. Should PHMSA require that operators perform a critical 
analysis of all factors that influence SCC to determine if SCC is a 
credible threat for each pipeline segment? If so, why? What experience 
based indications have proven reliable in determining whether SCC could 
be present?
    1. INGAA, supported by a number of pipeline operators, noted that 
operators are already required to perform an analysis to determine the 
likelihood of SCC. INGAA added that operators address the pipelines 
with the highest likelihood of SCC and apply lessons learned, as 
appropriate, to lower-likelihood pipelines.
    2. Texas Pipeline Association and Texas Oil & Gas Association 
indicated that a requirement to perform a critical analysis for SCC is 
unnecessary, since guidance in ASME/ANSI B31.8S is sufficient. Northern 
Natural Gas also stated that additional requirements are unnecessary, 
noting that it conducted an analysis of critical factors affecting SCC 
and identified no new factors over those in B31.8S, Appendix 3.
    3. Atmos stated that PHMSA's question was unclear whether to expand 
the threat of SCC to all pipeline segments or expand the requirements 
for investigating the presence of SCC within HCA segments? Atmos 
concluded that subpart O requirements provide a framework for operators 
to integrate data, rank risk, identify threats, and apply appropriate 
mitigative actions; additional requirements are not needed.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
suggested that PHMSA conduct a workshop to share industry experience 
with SCC.
Response to Question I.18 Comments
    PHMSA appreciates the information provided by the commenters and 
will consider this information in its study of comprehensive safety 
requirements for SCC.
    I.19. Should PHMSA require an integrity assessment using methods 
capable of detecting SCC whenever a credible threat of SCC is 
identified?

[[Page 20789]]

    1. INGAA, Panhandle, Atmos, and Northern Natural Gas noted that 
subpart O already requires that all credible threats be identified and 
assessed. A number of pipeline operators supported INGAA's comments.
    2. Texas Pipeline Association and Texas Oil & Gas Association also 
indicated that they read subpart O as requiring assessment using a 
method that can detect SCC if that threat is credible. The associations 
both added, however, that they would not object to making this 
requirement more explicit.
    3. GPTC opined that existing regulations and standards are adequate 
to address SCC issues.
    4. Southwest Gas opposed a new requirement, noting that Sec.  
192.929 and ASME/ANSI B31.8S are sufficient.
Response to Question I.19 Comments
    PHMSA appreciates the information provided by the commenters and 
will consider this information in its study of comprehensive safety 
requirements for SCC. As indicated above in the response to comments 
received on question I.5, PHMSA proposes more explicit requirements for 
selection of appropriate methods for integrity assessments for SCC.
    I.20. Should PHMSA require a periodic analysis of the effectiveness 
of operator corrosion management programs, which integrates information 
about CP, coating anomalies, in-line inspection data, corrosion coupon 
data, corrosion inhibitor usage, analysis of corrosion products, 
environmental and soil data, and any other pertinent information 
related to corrosion management? Should PHMSA require that operators 
periodically submit corrosion management performance metric data?
    1. INGAA, Kern River, Paiute, and Southwest Gas commented that 
these issues are already addressed in subpart O, which requires 
operators to keep records, measure program effectiveness, continually 
evaluate and assess systems, integrate data, and show continual 
improvement. INGAA added that metrics bearing on the effectiveness of a 
corrosion control program are already among those required to be 
collected by ASME/ANSI B31.8S. These metrics are not required to be 
submitted, but are available for review during inspections. A number of 
pipeline operators supported INGAA's comments.
    2. MidAmerican commented that subparts I and O include these 
requirements. Northern Natural Gas agreed that it manages these threats 
through O&M and IM activities.
    3. Panhandle noted that subpart I requires operators to maintain 
effective corrosion control programs to mitigate the threat of 
corrosion and Sec.  192.945 requires operators to measure, on a semi-
annual basis, whether the integrity management program is effective in 
assessing and evaluating the integrity of each covered pipeline segment 
and in protecting HCAs.
    4. GPTC and AGA, supported by a number of its pipeline operator 
members, opposed requiring operators to submit corrosion management 
metrics. AGA noted that operators need flexibility to select the 
appropriate analysis methods and key performance indicators. 
Furthermore, operators review corrosion control program effectiveness, 
and plans of intrastate operators are reviewed by state commissions.
    5. Ameren Illinois opposed new requirements, noting that subpart O 
already requires operators to identify and respond to risks.
    6. Atmos questioned whether PHMSA is proposing to measure the 
effectiveness of corrosion management programs across all pipeline 
segments or to measure the effectiveness of corrosion management 
programs in HCA segments. Atmos added that the data points enumerated 
by PHMSA in this question would be difficult to gather on an operator's 
entire pipeline system.
    7. Texas Pipeline Association and Texas Oil & Gas Association 
stated that they do not see a need for a requirement to periodically 
analyze the effectiveness of an operator's corrosion management 
program, arguing that existing requirements are sufficient.
    8. Panhandle argued that the standardization of corrosion control 
efforts, as would be required for performance metric tracking, would 
require additional prescriptive requirements in subpart O. Panhandle 
does not believe that elimination of performance-based language is 
beneficial.
    9. The Commissioners of Wyoming County Pennsylvania suggested that 
any communication between operators and PHMSA regarding corrosion 
management would be helpful in facilitating operator compliance and 
best practices.
    10. Paiute and Southwest Gas reported that they opposed a 
requirement to report additional performance metrics absent a 
definition of how new data would be collected and used.
Response to Question I.20 Comments
    PHMSA appreciates the information provided by the commenters. 
Following publication of the ANPRM, the NTSB issued recommendations in 
response to the San Bruno pipeline incident, including a specific 
recommendation (P-11-19) that PHMSA establish standards for evaluating 
effective program performance. PHMSA will evaluate standards for 
integration of pipeline corrosion data to enhance corrosion management 
performance as part of its response to that recommendation.
    I.21. Are any further actions needed to address corrosion issues?
    1. INGAA, supported by a number of its pipeline operator members, 
commented that continued study and evaluation of the root causes of the 
San Bruno explosion, documentation of findings, and communication of 
results are needed rather than additional prescriptive requirements.
    2. AGA, GPTC, and a number of pipeline operators argued that no 
further action is needed, given that current methodologies adequately 
address corrosion issues and operators are subject to periodic audits 
by federal and state safety regulators.
    3. Accufacts suggested that PHMSA needs to assure that IM programs 
are not solely relied upon to prevent corrosion failure.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
reported that they do not see any deficiencies necessitating new 
regulations.
Response to Question I.21 Comments
    PHMSA appreciates the information provided by the commenters. As 
discussed above, PHMSA is proposing some enhanced measures for 
corrosion control in subpart I and subpart O.
    I.22. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

J. Pipe Manufactured Using Longitudinal Weld Seams

    The ANPRM requested comments regarding additional integrity 
management and pressure testing

[[Page 20790]]

requirements for pipe manufactured using longitudinal seam welding 
techniques that have not had a subpart J pressure test. Pipelines built 
since the regulations (49 CFR part 192) were implemented in early 1971 
must be:
     Pressure tested after construction and prior to being 
placed into gas service in accordance with subpart J; and
     Manufactured in accordance with a referenced standard 
(most gas transmission pipe has been manufactured in accordance with 
American Petroleum Institute Standard 5L, 5LX or 5LS, ``Specification 
for Line Pipe'' (API 5L) referenced in 49 CFR part 192).
    Many gas transmission pipelines built from the 1940's through 1970 
were manufactured in accordance with API 5L, but may not have been 
pressure tested similar to a subpart J pressure test. For pipelines 
built prior to 1971, Sec.  192.619(a) allows MAOP to be based on the 
highest 5-year operating pressure established prior to July 1, 1970, in 
lieu of a pressure test. Accordingly, some of this pre-existing pipe 
possesses variable characteristics throughout the longitudinal weld or 
pipe body.
    As a result of 12 hazardous liquid pipeline failures that occurred 
during 1986 and 1987 involving pre-1970 ERW pipe, PHMSA issued an alert 
notice (ALN-88-01, January 28, 1988) to advise operators with pre-1970 
ERW pipe of the 12 pipeline failures and the actions to take. 
Subsequent to this notice, one additional failure on a gas transmission 
pipeline, and eight additional failures on hazardous liquid pipelines 
occurred, which resulted in PHMSA issuing another alert notice (ALN-89-
01, March 8, 1989) to advise operators of additional findings since the 
previous alert notice. These notices identified the fact that some 
failures appeared to be due to selective seam weld corrosion, but that 
other failures appeared to have resulted from flat growth of 
manufacturing defects in the ERW seam. In these notices, PHMSA 
specifically advised all gas transmission and hazardous liquid pipeline 
operators with pre-1970 ERW pipe to consider hydrostatic testing of 
affected pipelines, to avoid increasing a pipeline's long-standing 
operating pressure, to assure effectiveness of the CP system, and to 
conduct metallurgical exams in the event of an ERW seam failure.
    Since 2002, there have been at least 22 reportable incidents on gas 
transmission pipeline caused by manufacturing or seam defects. In 
addition, recent high consequence incidents, including the 2009 failure 
in Palm City, Florida and the 2010 failure in San Bruno, California, 
have been caused by longitudinal seam failures.
    The ANPRM listed questions for consideration and comment. The 
following are general comments received related to the topic as well as 
comments related to the specific questions:
General Comment for Topic J
    1. Texas Pipeline Association and Texas Oil & Gas Association 
suggested that seam issues are best addressed through inspection, 
detection, remediation, and monitoring, based on specific segments, not 
a one-size-fits-all requirement.
Response to General Comment for Topic J
    PHMSA appreciates the comment and agrees that a one-size-fits-all 
requirement is not the best approach. Accordingly, PHMSA proposes 
requirements for verification of MAOP in new Sec.  192.624 for onshore, 
steel, gas transmission pipelines, that are located in an HCA or MCA 
and meet any of the conditions in Sec.  192.624(a)(1) through (a)(3). 
Verification of MAOP includes establishing and documenting MAOP if the 
pipeline segment: (1) Has experienced a reportable in-service incident, 
as defined in Sec.  191.3, since its most recent successful subpart J 
pressure test, due to an original manufacturing-related defect, a 
construction-, installation-, or fabrication-related defect, or a 
cracking-related defect, including, but not limited to, seam cracking, 
girth weld cracking, selective seam weld corrosion, hard spot, or 
stress corrosion cracking and the pipeline segment is located in one of 
the following locations: (i) A high consequence area as defined in 
Sec.  192.903; (ii) a class 3 or class 4 location; or (iii) a moderate 
consequence area as defined in Sec.  192.3 if the pipe segment can 
accommodate inspection by means of instrumented inline inspection tools 
(i.e., ``smart pigs''); (2) Pressure test records necessary to 
establish maximum allowable operating pressure per subpart J for the 
pipeline segment, including, but not limited to, records required by 
Sec.  192.517(a), are not reliable, traceable, verifiable, and complete 
and the pipeline segment is located in one of the following locations: 
(i) A high consequence area as defined in Sec.  192.903; or (ii) a 
class 3 or class 4 location; or (3) the pipeline segment maximum 
allowable operating pressure was established in accordance with Sec.  
192.619(c) of this subpart before [effective date of rule] and is 
located in one of the following areas: (i) A high consequence area as 
defined in Sec.  192.903; (ii) a class 3 or class 4 location; or (iii) 
a moderate consequence area as defined in Sec.  192.3 if the pipe 
segment can accommodate inspection by means of instrumented inline 
inspection tools (i.e., ``smart pigs'').
    In addition, the proposed rule would allow operators to select from 
among several approaches to verify MAOP based on segment specific 
issues and limitations, such as pressure testing, pressure reduction 
based on historical operating pressure, and engineering critical 
assessment.
    Comments submitted for questions in Topic J.
    J.1. Should all pipelines that have not been pressure tested at or 
above 1.1 times MAOP or class location test criteria (Sec. Sec.  
192.505, 192.619 and 192.620), be required to be pressure tested in 
accordance with the present regulations? If not, should certain types 
of pipe with a pipeline operating history that has shown to be 
susceptible to systemic integrity issues be required to be pressure 
tested in accordance with the present regulations (e.g., low-frequency 
electric resistance welded (LF-ERW), direct current electric resistance 
welded (DC-ERW), lap-welded, electric flash welded (EFW), furnace butt 
welded, submerged arc welded, or other longitudinal seams)? If so, why?
    1. AGA, GPTC, and numerous pipeline operators opposed a requirement 
to pressure test all lines not previously tested. These commenters 
supported the more-limited testing mandated by the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011. AGA noted that 
Congress considered and rejected proposals for more extensive testing.
    2. AGA, GPTC, Iowa Utilities Board, Iowa Association of Municipal 
Utilities, Texas Pipeline Association, Texas Oil & Gas Association, and 
several distribution pipeline operators objected to requiring pressure 
testing of distribution pipelines. The commenters argued that the 
impact of resulting service disruptions was overlooked. Pressure 
testing would necessitate disruptions of three to seven days for many 
distribution pipelines, sometimes involving service to an entire town. 
In some cases, establishing an alternate supply is not always possible. 
In addition, some in-service lines are not configured in a manner that 
would support testing. For these reasons, the commenters argued that 
the high costs to perform pressure tests were inappropriate absent some 
demonstration of actual risk. MidAmerican added a suggestion that such 
a requirement of this type be

[[Page 20791]]

limited to pipelines operating above 30 percent of specified minimum 
yield strength (SMYS). Northern Natural Gas agreed with MidAmerican's 
suggestion and would further limit any testing requirement to pipelines 
outside of Class 1 locations and subject to seam issues.
    3. INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas 
Association, and several pipeline operators opposed a blanket testing 
requirement for older pipelines. The commenters noted that more than 
sixty percent of in-service pipelines were installed prior to 1970, and 
have operated safely. INGAA argued that the objective of any action in 
this area should not be pressure testing, per se, but verification of 
fitness for service. INGAA noted that all of the listed pipe types are 
addressed in its Fitness for Service protocol, which would be more 
effective and efficient than a prescriptive test requirement. A number 
of additional pipeline operators supported INGAA's comments.
    4. Accufacts recommended that all pipelines with at-risk seam 
anomalies be pressure tested to at least 90% SMYS, with priority given 
to lines operating under an MAOP established in accordance with 49 CFR 
192.619(c).
    5. Texas Pipeline Association and Texas Oil & Gas Association noted 
that pressure testing alone, is not sufficient to prove the integrity 
of pipelines subject to seam issues. The associations argued that 
verification must also consider any degradation mechanism present in 
the seam.
    6. Dominion East Ohio supported a requirement to pressure test pipe 
susceptible to seam failure for which adequate test documentation does 
not exist.
    7. Pipeline Safety Trust, California Public Utilities Commission, 
Commissioners of Wyoming County Pennsylvania, and an anonymous 
commenter supported requiring a pressure test for all pipelines not 
already tested to current requirements. The commenters argued that 
integrity management should have led to necessary testing but has not 
done so in all cases. They also noted that such a requirement would 
respond to an NTSB recommendation.
    8. The Environmental Defense Fund (EDF) cautioned that any 
requirement for pressure testing should assure that the amount of gas 
blown down to the atmosphere is minimized. It noted that methane is a 
potent greenhouse gas, and uncontrolled blowdown of 182,000 miles of 
gas transmission pipeline would be approximately equivalent to the 
annual greenhouse gas release from 9-14 million autos.
Response to Question J.1 Comments
    PHMSA appreciates the information provided by the commenters. This 
NPRM proposes requirements for verification of MAOP in new Sec.  
192.624 for onshore, steel, gas transmission pipelines that are located 
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1) 
through (a)(3). Verification of MAOP includes establishing and 
documenting MAOP using one or more of the methods in Sec.  
192.624(c)(1) through (c)(6). With regard to the EDF comment regarding 
the environmental cost due to gas blow down during pressure testing, 
PHMSA considered this in the rule development. The proposed rulemaking 
is written to minimize pressure testing. The Integrity Verification 
Process allows MAOP verification through ILI and ECA. PHMSA believes 
operators will pressure test as a last resort because it is the 
costliest methodology. PHMSA estimates that the rule would result in 
approximately 1,300 miles of pipe being pressure tested. The gas 
release from controlled low volume release during pressure testing is 
much less than an uncontrolled high volume release as a result of 
rupture. The proposed rule is expected to prevent incidents, leaks, and 
other types of failures that might occur, thereby preventing future 
releases of greenhouse gases (GHG) to the atmosphere, thus avoiding 
additional contributions to global climate change. PHMSA estimated net 
GHG emissions abatement over 15 years of 69,000 to 122,000 metric tons 
of methane and 14,000 to 22,000 metric tons of carbon dioxide, based on 
the estimated number of incidents averted and emissions from pressure 
tests and ILI upgrades.
    J.2. Are alternative minimum test pressures (other than those 
specified in subpart J) appropriate, and why?
    1. INGAA, supported by a number of pipeline operators, argued that 
there is no evidence suggesting that subpart J test pressures are 
inadequate. INGAA added that there are circumstances in which 
additional tests to 1.25 times MAOP may be appropriate to verify 
fitness for service. This is consistent with ASME/ANSI B31.8S and 
addressed in its Fitness for Service protocol.
    2. Texas Pipeline Association, Texas Oil & Gas Association, and 
Atmos argued that a pressure test at the time of construction is 
adequate. The associations further added that operating practices since 
part 192 became effective can also verify fitness for service, if 
primary test records are not available, particularly if MAOP is 
reduced.
    3. AGA, GPTC, and a number of pipeline operators commented that any 
test to pressures greater than MAOP has some value. AGA noted that even 
tests to 1.1 times MAOP would identify the most severe defects that 
have the potential to adversely affect pipeline integrity.
    4. MidAmerican suggested that a fitness for service evaluation 
should be allowed if there are service interruption issues and for pre-
1970 pipelines. MidAmerican would allow testing for existing pipelines, 
to 1.1 or 1.25 times MAOP or to mill test pressures if they are less 
than would be required by subpart J.
    5. An anonymous commenter argued that alternative minimum test 
pressures are not appropriate, since they provide no more information 
than successful operation at normal operating pressures.
    6. Accufacts suggested that pipelines tested to lower pressures and 
that have been subject to aggressive operating cycles be considered for 
high-pressure testing. Accufacts would also require test pressures be 
recorded both in psig and percent SMYS.
Response to Question J.2 Comments
    PHMSA appreciates the information provided by the commenters. 
Following publication of the ANPRM, the NTSB issued its report on the 
San Bruno incident that included a recommendation for this issue (P-11-
15). The NTSB recommended that PHMSA amend its regulations so that 
manufacturing- and construction-related defects can only be considered 
``stable'' if a gas pipeline has been subjected to a post-construction 
hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM 
proposes to revise the integrity management requirement in 
192.917(e)(3) to allow the presumption of stable manufacturing and 
construction defects only if the pipe has been pressure tested to at 
least 1.25 times MAOP. In addition, PHMSA proposes to revise pressure 
test safety factors in Sec.  192.619(a)(2)(ii) to correspond to at 
least 1.25 MAOP for newly installed pipelines.
    J.3. Can ILI be used to find seam integrity issues? If so, what ILI 
technology should be used and what inspection and acceptance criteria 
should be applied?
    1. INGAA and numerous pipeline operators noted that ILI tools can 
examine seam issues but the technology to identify and evaluate seam 
anomalies is still evolving. INGAA added that there are significant 
burdens associated

[[Page 20792]]

with requiring pressure testing as an alternative.
    2. AGA reported that its discussions with ILI vendors have 
identified that ILI can detect seam issues but detection is dependent 
on many conditions and is not guaranteed.
    3. Texas Pipeline Association and Texas Oil & Gas Association 
argued that ILI conducted using a multi-purpose tool can provide a seam 
assessment equivalent to pressure testing for detection of seam 
integrity issues, depending on anomaly characteristics and the ILI 
method used.
    4. Northern Natural Gas commented that ILI can be used to detect 
seam anomalies. Analysis of anomalies is based on the log-secant method 
with consideration of toughness to determine the predicted failure 
pressure ratio. The response criteria can then be based on the failure 
pressure versus maximum allowable operating pressure, similar to wall 
loss. Northern noted that this is consistent with ASME/ANSI B31.8 and 
B31.8S.
    5. Accufacts commented that ILI cannot, at present, reliably detect 
all seam anomalies.
Response to Question J.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
proposes requirements in the rulemaking to address the use of ILI for 
seam integrity issues. This includes incorporating industry standard 
NACE SP0102-2010 into the regulations to provide better guidance for 
conducting integrity assessments with in-line inspection. In addition, 
for pipe segments subject to MAOP verification in new Sec.  192.624, 
specific guidance is provided for analyzing crack stability when using 
engineering critical assessment in conjunction with inline inspection 
to address seam or other cracking issues.
    J.4. Are other technologies available that can consistently be used 
to reliably find and remediate seam integrity issues?
    1. INGAA and numerous pipeline operators noted that magnetic 
particle inspection is now being used by many operators when pipe with 
disbanded coating is exposed.
    2. GPTC, Northern Natural Gas, and MidAmerican reported that there 
are other methods that are useful under some circumstances, such as x-
ray or other forms of radiography and guided wave ultrasound.
    3. Texas Pipeline Association, Texas Oil & Gas Association, and 
Atmos noted that radiography, ultrasonic testing (UT), and shear wave 
UT are now being tested.
    4. AGA, supported by a number of its pipeline operator members, 
noted that operators must have the flexibility to select appropriate 
tools without prior PHMSA approval. AGA argued that technology is 
advancing rapidly and that PHMSA stifles advancement by requiring prior 
approval of new inspection tools. AGA argued that some requirements 
being imposed on the use of other technologies are effectively 
regulations imposed without formal rulemaking, citing limitations 
imposed on the use of guided wave ultrasound as an example.
    5. Atmos recommended that PHMSA modify its regulations to allow 
operators to use appropriate methods to evaluate seam integrity without 
requiring approval as ``other technology.''
    6. Accufacts opined that pressure testing and cyclic monitoring and 
analysis are the only useful technologies currently available.
Response to Question J.4 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
proposes requirements in the rulemaking to address the use of best 
available technology, including use of electromagnetic acoustic 
transducers (EMAT) or ultrasonic testing (UT) tools to assess seam 
integrity issues. In addition, proposed requirements include performing 
fracture mechanics modeling for failure stress pressure and cyclic 
fatigue crack growth analysis to assess crack or crack-like defects. 
These requirements would apply to any segment that required 
verification of MAOP.
    J.5. Should additional pressure test requirements be applied to all 
pipelines, or only pipelines in HCAs, or only pipelines in Class 2, 3, 
or 4 location areas?
    1. INGAA and several pipeline operators argued that existing 
requirements are adequate and any verification beyond those 
requirements should rely on INGAA's Fitness for Service protocol. INGAA 
argued that its protocol is consistent with Section 23 of the Pipeline 
Safety, Regulatory Certainty, and Job Creation Act of 2011.
    2. MidAmerican suggested any new requirements should focus on pipe 
with manufacturing and construction defects and should prioritize 
pipelines in Class 3 and 4 areas and HCAs. MidAmerican sees little 
benefit in testing other pipelines.
    3. An anonymous commenter recommended additional unspecified 
requirements be applied to pipelines in Class 3 and 4 areas and HCAs.
    4. The California Public Utilities Commission would apply pressure 
testing requirements to HCAs that are determined by the method 
described in paragraph 1 in the definition of HCA in Sec.  192.903, as 
a minimum.
    5. The Iowa Utilities Board and the Iowa Association of Municipal 
Utilities argued that class location is not a reasonable basis for 
determining where to apply pressure testing requirements, given that 
class location has no relationship to risk. These commenters noted that 
small-diameter, low-pressure lines could be Class 3, even with no 
structures intended for human occupancy within a potential impact 
radius.
    6. The Commissioners of Wyoming County Pennsylvania would apply 
requirements to all transmission and gathering pipelines, including 
those in Class 1 locations.
    7. Thomas Lael noted that all pipelines have been tested once, 
after construction.
Response to Question J.5 Comments
    PHMSA appreciates the information provided by the commenters. This 
NPRM proposes requirements for verification of MAOP in new Sec.  
192.624 for onshore, steel, gas transmission pipelines that are located 
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1) 
through (a)(3). Use of the MCA location criteria would apply to pipe 
segments where dwellings, occupied sites, or interstate highways, 
freeways, and expressways, and other principal 4-lane arterial roadways 
are located within the potential impact radius, but would not 
necessarily include all class 3 or 4 locations. Verification of MAOP 
includes establishing and documenting MAOP using one or more of the 
methods in 192.624(c)(1) through (c)(6). In addition, this NPRM 
proposes requirements for verification of pipeline material in new 
Sec.  192.607 for existing onshore, steel, gas transmission pipelines 
that are located in an HCA or class 3 or class 4 locations.
    J.6. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements pursuant to commenter's suggestions.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.

[[Page 20793]]

     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

K. Establishing Requirements Applicable to Underground Gas Storage

    Underground storage facilities are comprised of wells and 
associated separation, compression, and metering facilities to inject 
and withdraw natural gas at high pressures from depleted hydrocarbon 
reservoirs and salt caverns. Pipelines that transport gas within a 
storage field are defined in Sec.  192.3 as transmission pipelines and 
are regulated by PHMSA, while underground storage facilities including 
surface and subsurface well casing, tubing, and valves are not 
currently regulated under part 192. In the ANPRM, PHMSA provided a 
brief history of a 1992 accident that occurred in Brenham, Texas an 
involving underground storage facility. This incident involved an 
uncontrolled release of highly volatile liquids from a salt dome 
storage cavern that resulted in 3 fatalities, 21 people treated for 
injuries at area hospitals, and damages in excess of $9 million. 
Following the incident, the National Transportation Safety Board (NTSB) 
conducted an investigation that resulted in a recommendation for the 
Research and Special Programs Administration, the precursor to PHMSA, 
to initiate a rulemaking proceeding. Following a period of study, RSPA 
terminated that rulemaking. RSPA described this action in an Advisory 
Bulletin published in the Federal Register on July 10, 1997 (ADB-97-04, 
62 FR 37118).
    Since publication of the 1997 Advisory Bulletin, significant 
incidents have continued to occur involving underground gas storage 
facilities. The most significant incident occurred in 2001 near 
Hutchinson, Kansas. An uncontrolled release from an underground gas 
storage facility resulted in an explosion and fire, in which two people 
were killed. Many residents were evacuated from their homes and were 
not able to return for four months.
    The Kansas Corporation Commission initiated enforcement action 
against the operator of the Hutchinson storage field as a result of 
safety violations associated with the accident. As part of this 
enforcement proceeding, it was concluded that the storage field was an 
interstate gas pipeline facility. Federal statutes provide that ``[a] 
State authority may not adopt or continue in force safety standards for 
interstate pipeline facilities or interstate pipeline transportation'' 
(49 U.S.C. 60104). There were, and remain, no federal safety standards 
against which enforcement could be taken. Therefore, the enforcement 
proceeding was terminated.
    The ANPRM listed questions for consideration and comment. The 
following are general comments received related to this topic as well 
as comments related to the specific questions:
General Comments for Topic K
    1. AGA, supported by a number of pipeline operators, suggested that 
any proceeding addressing gas storage be conducted under a docket 
separate from any pipeline requirements, arguing that the relevant 
engineering and regulatory concepts are vastly different.
    2. The Kansas Department of Health and Environment (KDHE) noted 
that the ANPRM misstated the agency that took enforcement action in the 
case of the Kansas gas storage incident previously discussed. That 
action was taken by KDHE, and not the Kansas Corporation Commission, as 
stated.
    3. Kansas Corporation Commission recommended that PHMSA work with 
the states to have Congress amend the Pipeline Safety Act to allow the 
states to regulate interstate and intrastate gas storage wellbores. KCC 
noted that current federal regulations undermine the ability of states 
to regulate gas storage facilities, as in the 2001 accident where 
Kansas attempted to take enforcement as a result of a serious incident 
but was precluded from doing so by pre-emption of federal regulations.
    4. The Interstate Oil & Gas Compact Commission argued that states 
should be mandated to regulate gas storage wellbores, whether 
interstate or intrastate.
    5. The Texas Pipeline Association and Texas Oil & Gas Association 
opposed new requirements, arguing that there has been no demonstration 
of undue risk or insufficiency of current regulations.
    Comments submitted for questions in Topic K.
    K.1. Should PHMSA develop Federal standards governing the safety of 
underground gas storage facilities? If so, should they be voluntary? If 
so, what portions of the facilities should be addressed in these 
standards?
    1. INGAA suggested that PHMSA develop high-level, performance-based 
guidelines that acknowledge and reflect existing applicable state rules 
to address regional and geologic variations in underground storage 
activity. Development of guidelines should follow PHMSA's current 
practice of stakeholder involvement leading to development of a 
consensus standard and its subsequent adoption into regulations. INGAA 
reported that it is committed to developing a standard under the 
auspices of the American Petroleum Institute (API), with work beginning 
in 2012. INGAA cautioned that it is important to understand, and 
clearly state, the scope of ``gas storage,'' which it contends begins 
at and includes the wing valve at the wellhead, the wellhead 
components, the well bore, and the ``underground container'' (i.e., the 
geologic formation). INGAA stated that PHMSA should recognize the 
limits and requirements imposed on gas storage by FERC, arguing that no 
new regulations are needed in these areas. A number of pipeline 
operators supported INGAA's comments, and have submitted separate 
comments addressing one or more of these points.
    2. AGA suggested that PHMSA adopt federal performance standards, in 
conjunction with API. AGA argued that one-size-fits-all requirements 
are not appropriate in this area, since they would fail to recognize 
variations in wells and the geologic diversity of storage caverns and 
structures. AGA argued that no new requirements are needed governing 
maximum operating parameters and environmental conditions, since these 
are addressed adequately by existing federal and state certification 
and compliance programs related to gas storage facilities. AGA 
recommended that any new standards should be mandatory, but also 
recognize regional variations by state due to geologic and geographical 
diversity among storage fields. A number of pipeline operators 
supported AGA's comments.
    3. INGAA, the Kansas Corporation Commission, and the Interstate Oil 
& Gas Compact Commission recommended that compliance with any new 
standards be mandatory, but that regulatory authority should be 
delegated to the states since PHMSA lacks relevant technical expertise. 
A number of pipeline operators supported this comment.
    4. The Kansas Corporation Commission and the Interstate Oil & Gas 
Compact Commission recommended that any new standards cover all 
portions of a storage facility and that PHMSA enter into a memorandum 
of understanding with FERC regarding gas containment.
    5. Southern Star Central Gas Pipeline agreed that the development 
of requirements for operation of gas storage facilities is appropriate 
but explicitly disagreed with Kansas Corporation Commission's 
suggestion that development be delegated to states.

[[Page 20794]]

Southern Star indicated that it would not object to the delegation of 
inspection and enforcement to federal standards. Southern Star noted 
that a federal court has held only federal regulations can be enforced 
against its storage facilities. The company also argued that no new 
requirements are needed for storage reservoirs given existing FERC 
regulations.
    6. GPTC, Nicor, Ameren Illinois, and Atmos argued that existing 
regulations are sufficient and that no new standards are needed. GPTC 
and Nicor added that if PHMSA elects to develop new requirements, they 
should be limited to facilities ``affecting interstate or foreign 
commerce.'' Atmos added that geology and circumstances vary 
considerably among gas storage facilities and states have the requisite 
expertise to regulate storage safety.
    7. Texas Pipeline Association and Texas Oil & Gas Association 
argued that PHMSA lacks the expertise to regulate wellbores and 
therefore should not attempt to develop gas storage regulations.
    8. FERC, NAPSR, Interstate Oil & Gas Compact Commission, Iowa 
Utilities Board, Kansas Corporation Commission, and Railroad Commission 
of Texas recommended that PHMSA seek statutory authority to confer 
jurisdiction over all gas storage facilities to the states. The 
commenters argued that states have expertise on local geology and 
storage fields and could therefore regulate in a fashion similar to 
that of production facilities. The commenters referred to PHMSA's 
Advisory Bulletin ADB 97-04 as a further basis for this recommendation. 
FERC further suggested that PHMSA delegate inspection and enforcement 
activities to states if statutory changes are not forthcoming.
    9. The Alaska Department of Natural Resources recommended that 
PHMSA develop standards in consultation with the states.
    10. The NTSB encouraged the development of gas storage regulations, 
noting that this was the subject of its recommendation P-93-9, which it 
closed as ``unacceptable action,'' after a rulemaking proceeding to 
regulate underground gas storage was terminated in 1997.
    11. A private citizen suggested that there should be some level of 
regulation, as gas storage is currently insufficiently regulated.
    12. NAPSR commented that, in many states, the agency familiar with 
gas storage issues is not responsible for regulation of pipeline 
safety. As a result, NAPSR stated that certification of additional 
state agencies may be required.
    13. An anonymous commenter suggested that PHMSA should develop 
requirements applicable to piping within gas storage facilities. The 
commenter argued that caverns, well heads, casing, tubing, fresh water, 
and brine pumping are generally regulated by states.
    14. ITT Exelis Geospatial Systems suggested that PHMSA consider 
requirements for leak detection, noting that their LIDAR system could 
serve this purpose.
    K.2. What current standards exist governing safety of these 
facilities? What standards are presently used for conducting casing, 
tubing, isolation packer, and wellbore communication and wellhead 
equipment integrity tests for down-hole inspection intervals? What are 
the repair and abandonment standards for casings, tubing, and wellhead 
equipment when communication is found or integrity is compromised?
    1. AGA, INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas 
Association and numerous pipeline operators noted that FERC, EPA, and 
the states regulate various aspects of gas storage. Commenters reported 
that state regulations generally provide standards for wells and that 
EPA regulations provide standards for caverns. AGA described the 
aspects regulated by FERC, EPA, and the states and suggested provisions 
of each which might be considered for new PHMSA regulations. For 
example, it was recommended that a federal guideline be established to 
require a storage operator notification-review-and-approval process for 
third party wells encroaching on storage containers, which is a 
requirement some states currently have in place. Commenters reported 
that repaired wells must meet state standards for new wells and state 
requirements for abandonment vary. AGA indicated that interstate 
storage operators use state requirements as guidance in the absence of 
federal regulations.
    2. The Kansas Department of Health and Environment, the Kansas 
Corporation Commission, the Railroad Commission of Texas, the 
Interstate Oil & Gas Compact Association, Ameren Illinois, and Atmos 
reported that states generally regulate gas storage. For example, in 
Texas, Statewide Rule 16 applies and KDHE submitted a copy of its gas 
storage regulations.
    3. Texas Pipeline Association and Texas Oil & Gas Association noted 
that Texas requirements for gas storage are more similar to provisions 
that would govern production drilling and operations rather than 
pipeline operations.
    K.3. What standards are used to monitor external and internal 
corrosion?
    1. AGA, INGAA, and numerous pipeline operators noted that varying 
approaches are used and argued that prescriptive standards would be 
inappropriate given that no one tool is applicable to all wells and 
well casings are not available for direct examination.
    2. The Railroad Commission of Texas reported that its regulations 
require integrity testing every five years or after a well work over. 
Texas regulations also require periodic casing inspections and a 
pipeline integrity program.
    3. Northern Natural Gas reported that it uses the same measures to 
monitor corrosion in its gas storage facilities as it does for its 
pipelines.
    K.4. What standards are used for welding, pressure testing, and 
design safety factors of casing and tubing including cementing and 
casing and casing cement integrity tests?
    1. INGAA, AGA, the Texas Pipeline Association, the Texas Oil & Gas 
Association and numerous pipeline operators noted that state 
requirements reflect unique situations, welding is seldom used, 
pressure capacity is demonstrated by historical record, and casing 
requirements are customized for local geologic conditions. Welding, 
when used, is generally performed to procedures compliant with ASTM 
B31.8, part 192, and inspection is conducted to API-1104 criteria.
    2. The Railroad Commission of Texas reported that Texas regulations 
are flexible to allow for site-specific decisions.
    K.5. Should wellhead valves have emergency shutdowns both primary 
and secondary? Should there be integrity and O&M intervals for key 
safety and CP systems?
    1. INGAA, AGA, and several pipeline operators reported that storage 
in salt domes generally requires emergency shutdown systems; these 
systems are generally not required for storage in depleted gas fields 
or aquifers but may be required depending on local site conditions. The 
commenters indicated that testing intervals are set in accordance with 
operator procedures and CP testing is based on an operator's local 
experience.
    2. The Railroad Commission of Texas, the Texas Pipeline 
Association, and the Texas Oil & Gas Association reported that Texas' 
regulations require emergency shutdown systems and annual drills.
    3. The Kansas Department of Health and Environment suggested that 
at least

[[Page 20795]]

the primary well should have an emergency shutdown system. KDHE stated 
that O&M intervals should be established for key safety systems and 
attached a copy of the relevant Kansas regulations to its comments.
    4. Northern Natural Gas suggested that emergency shutoffs should 
only be required when the well is within 330 feet of a structure 
intended for human occupancy. Northern stated that intervals should be 
established for O&M activities and CP systems.
    5. GPTC and Nicor expressed their opinion that no new regulations 
are needed in this area; decisions on emergency shutdown should be made 
based on local circumstances.
    K.6. What standards are used for emergency shutdowns, emergency 
shutdown stations, gas monitors, local emergency response 
communications, public communications, and O&M Procedures?
    1. AGA, GPTC, and several pipeline operators reported that 
operators generally follow DOT regulations, where applicable, and 
industry good practices.
    2. The NTSB commented that gas storage facility information should 
be made available to emergency responders, per its recommendation P-11-
8.
    3. The Railroad Commission of Texas, the Texas Pipeline 
Association, the Texas Oil & Gas Association, and Atmos reported that 
states establish standards in these areas through their regulations.
    4. The Kansas Department of Health and Environment reported that 
these standards are specified in its regulations, and submitted a copy 
of its regulations as an attachment to its comments.
    K.7. Does the current lack of Federal standards and preemption 
provisions in Federal law preclude effective regulation of underground 
storage facilities by States?
    1. INGAA, supported by several of its member companies, noted that 
jurisdiction over gas storage facilities in interstate pipeline systems 
is federal.
    2. AGA and several of its pipeline operator members suggested that 
federal standards could assure a degree of consistency, and uniform 
standards would promote integrity and safety. AGA opined that 
implementation of federal standards could be delegated to the states.
    3. GPTC and Nicor opined that federal regulations are not needed; 
as states are not now precluded from regulating gas storage and many do 
so.
    4. The Texas Pipeline Association, the Texas Oil & Gas Association, 
Atmos, Ameren Illinois, and Northern Natural Gas opined that effective 
state regulation is not now precluded. The commenters stated that state 
regulation in combination with applicable FERC and DOT requirements has 
been demonstrated to assure safety successfully.
    5. The Kansas Department of Health and Environment and the Kansas 
Corporation Commission noted that state regulation of the safety of 
interstate gas storage facilities is currently precluded. When Kansas 
attempted to enforce its requirements following an accident at an 
interstate storage facility, it was prevented from doing so by a 
federal court on the basis of federal preemption. The agencies noted 
that lack of action by PHMSA or FERC on interstate gas storage facility 
safety precludes states from taking any action and leaves these 
facilities essentially unregulated.
    K.8. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.
Response to All Topic K Comments
    Since the publication of the ANPRM and the close of its comment 
period, Southern California Gas Company's (SoCal Gas) Aliso Canyon 
Natural Gas Storage Facility Well SS25 failed, causing a sustained and 
uncontrolled natural gas leak near Los Angeles, California. The 
failure, possibly from the downhole well casing, resulted in the 
relocation of more than 4,400 families according to the Aliso Canyon 
Incident Command briefing report issued on February 1, 2016. On January 
6, 2016, California Governor Jerry Brown issued a proclamation 
declaring the Aliso Canyon incident a state emergency. On February 5, 
2016, PHMSA issued an advisory bulletin in the Federal Register (81 FR 
6334) to remind all owners and operators of underground storage 
facilities used for the storage of natural gas to consider the overall 
integrity of the facilities to ensure the safety of the public and 
operating personnel and to protect the environment. The advisory 
bulletin specifically reminded these operators to review their 
operations and identify the potential of facility leaks and failures, 
review the operation of their shut-off and isolation systems, and 
maintain updated emergency plans. In addition, PHMSA used the advisory 
bulletin to advocate the review of a previous advisory bulletin (97-04) 
dated July 10, 1997 and the voluntary implementation of American 
Petroleum Institute (API) 1170 ``Design and Operation of Solution-mined 
Salt Caverns Used for Natural Gas Storage, First Edition, July 2015,'' 
API RP 1171 ``Functional Integrity of Natural Gas Storage in Depleted 
Hydrocarbon Reservoirs and Aquifer Reservoirs, First Edition, September 
2015,'' and Interstate Oil and Gas Compact Commission (IOGCC) standards 
entitled ``Natural Gas Storage in Salt Caverns--A Guide for State 
Regulators'' (IOGCC Guide), as applicable. PHMSA will consider 
proposing a separate rulemaking to address the safety of underground 
natural gas storage facilities. Proposing a separate rulemaking that 
specifically focuses on improving the safety of underground natural gas 
storage facilities will allow PHMSA to fully consider the impacts of 
incidents that have occurred since the close of the initial comment 
period. It will also allow the Agency to consider voluntary consensus 
standards that were developed after the close of the comment period for 
this ANPRM, and to solicit feedback from additional stakeholders and 
members of the public to inform the development of potential 
regulations.

L. Management of Change

    The ANPRM requested comments regarding the addition of requirements 
for the management of change to provide a greater degree of control 
over this element of pipeline risk, particularly following changes to 
physical configuration or operational practices. Operation of a 
pipeline over an extended period without effective management of 
change, such as changes to pipeline systems (e.g., pipeline equipment, 
computer equipment or software used to monitor and control the 
pipeline) or to practices used to construct, operate, and maintain 
those systems, can result in safety issues. Changes can introduce 
unintended consequences if the change is not well thought out or is 
implemented in a manner not consistent with its design or planning. 
Similarly, changes in procedures require people to perform new or 
different actions, and failure to train them properly and in a timely

[[Page 20796]]

manner can result in unexpected consequences. The result can be a 
situation in which risk or the likelihood of an accident is increased. 
A recently completed but poorly-designed modification to the pipeline 
system was a factor contributing to the Olympic Pipeline accident in 
Bellingham, Washington. The following are general comments received 
related to this topic as well as comments related to the specific 
questions:
General Comments for Topic L
    1. INGAA and several of its pipeline operator members disagreed 
with the implication in the ANPRM that change management is not now 
addressed in regulations. They pointed out that Sec.  192.911(k) and 
ASME/ANSI B31.8S (incorporated by reference) already address this 
subject. INGAA reported that its members are committed to clarifying 
and expanding the use of a formal ``management of change'' process, and 
to facilitating its consistent application as a key management system. 
INGAA expressed its belief that the full adoption of ASME/ANSI B31.8S 
will facilitate the widespread application of these principles. 
Dominion East Ohio Gas also noted that part 192 already contains a 
management of change process. In addition, Chevron noted that 
management of change programs are generally specific to the 
organizational, operational, and ownership structures of the company, 
and part 192 already addresses this subject.
    2. A private citizen opined that management of change is 
necessarily an integral part of quality management systems and another 
private citizen supported management of change requirements, noting 
that accidents often result from changes to systems. The Alaska 
Department of Natural Resources also supported PHMSA's goal of 
establishing management of change requirements or guidelines.
Response to General Comments for Topic L
    PHMSA appreciates the information provided by the commenters. PHMSA 
agrees management of change is currently addressed in Sec.  192.911(k). 
However, because of its importance, and consistent with INGAA members' 
commitment to expanding use of formal MOC processes, PHMSA believes it 
is prudent to provide greater emphasis on MOC directly within the rule 
text.
    Therefore, PHMSA proposes to clarify integrity management 
requirements for management of change by explicitly including aspects 
of an effective management of change process into the rule text to 
emphasize the current requirements. In addition, PHMSA also proposes to 
add a new subsection 192.13(d) that would apply to onshore gas 
transmission pipelines, and require that an evaluation must be 
performed to evaluate and mitigate, as necessary, the risk to the 
public and environment as an integral part of managing pipeline design, 
construction, operation, maintenance and integrity, including 
management of change. The new paragraph would also articulate the 
general requirements for a management of change process, consistent 
with Section 192.911(k).
    Comments submitted for questions in Topic L.
    L.1. Are there standards used by the pipeline industry to guide 
management processes including management of change? Do standards 
governing the management of change process include requirements for IM 
procedures, O&M manuals, facility drawings, emergency response plans 
and procedures, and documents required to be maintained for the life of 
the pipeline?
    1. AGA, supported by several of its members, and several 
transmission pipeline operators questioned why this question was in the 
ANPRM, noting that management of change requirements are already 
promulgated in Sec.  192.911(k). GPTC added that Sec.  192.909 also 
addresses this subject.
    2. INGAA reported that Section 11 of ASME/ANSI B31.8S is the 
industry standard in this area, and all of the considerations in this 
question are included in operators' management of change processes. 
Several pipeline operators supported this comment.
    3. Atmos reported that it is not aware of any standards used by the 
industry to guide management of change processes. Atmos does not have a 
formal management of change process, except in its integrity management 
program, but expressed its conclusion that existing practices within 
the company contribute to its ability to manage change.
    4. Texas Pipeline Association (TPA) reported that its members do 
not have formal management of change processes but comply with 
regulations that address proxy requirements (e.g., Sec.  192.911). TPA 
expressed its belief that part 192, taken as a whole, includes 
management of change requirements to which its members adhere. Texas 
Oil & Gas Association supported TPA's comments.
    5. California Public Utilities Commission reported that it is 
unaware of any pipeline industry standards in this area.
    6. An anonymous commenter opined that most operators do not have 
management of change processes.
    7. The NTSB recommended that PHMSA require operators of natural gas 
transmission and distribution pipelines and hazardous liquid pipelines 
to ensure that their control room operators immediately notify the 
relevant 911 emergency call centers of possible ruptures 
(Recommendation P-11-9).
    8. TransCanada reported that it is committed to clarifying and 
expanding the use of a formal ``management of change'' process. 
TransCanada expressed its conclusion that the full adoption of ASME/
ANSI B31.8S will facilitate the widespread application of management of 
change principles.
Response to Question L.1 Comments
    PHMSA appreciates the information provided by the commenters, which 
did not identify any standards beyond ASME/ANSI B31.8S, which is 
already invoked by part 192, and used by the pipeline industry to guide 
management processes including management of change. See response to 
the general comments for Topic L, above.
    L.2. Are standards used in other industries (e.g., Occupational 
Safety and Health Administration standards at 29 CFR 1910.119) 
appropriate for use in the pipeline industry?
    1. INGAA reported that Section 11 of ASME/ANSI B31.8S is based on 
OSHA's Process Safety Management (PSM) standards. INGAA noted that OSHA 
worked with industry in developing PSM standards that would identify 
potential threats and assure that mitigative actions were taken. 
Several pipeline operators supported INGAA's comments.
    2. AGA and GPTC expressed their belief that there is no benefit in 
comparing standards with other industries, reiterating that Sec. Sec.  
192.909 and 192.911 and ASME/ANSI B31.8S already include management of 
change. Several pipeline operators supported AGA's comments.
    3. The Texas Pipeline Association and the Texas Oil & Gas 
Association reported that their members are aware of standards used in 
other industries but do not believe they are appropriate or applicable 
to the pipeline industry.
    4. The Iowa Association of Municipal Utilities expressed its 
conclusion that OSHA standards are complicated and would be unduly 
costly for small municipal utilities.
    5. Accufacts noted that transportation pipelines are specifically 
excluded from OSHA regulation; however, this does not prevent PHMSA 
from incorporating elements of 29 CFR 1910.119 into the

[[Page 20797]]

federal pipeline safety regulations in order to mandate a more prudent 
pipeline safety culture.
    6. Atmos reported that it has no experience with standards used in 
other industries but noted that OSHA standards appear to be directed 
toward situations where processes interact such that a change in one 
process affects a second or third process.
    7. Ameren Illinois suggested that standards from other industries 
would need to be studied to determine if they are applicable to the 
pipeline industry.
    8. An anonymous commenter suggested that the OSHA standards are a 
good model for pipelines, as they are well written and thought out.
Response to Question L.2 Comments
    PHMSA appreciates the information provided by the commenters. See 
response to the general comments for Topic L, above.
    L.3. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

M. Quality Management Systems (QMS)

    The ANPRM requested comments on whether and how to impose 
requirements related to quality management systems. Quality management 
includes the activities and processes that an organization uses to 
achieve quality. These include formulating policy, setting objectives, 
planning, quality control, quality assurance, performance monitoring, 
and quality improvement.
    Achieving quality is critical to gas transmission pipeline design, 
construction, and operations. PHMSA recognizes that pipeline operators 
strive to achieve quality, but our experience has shown varying degrees 
of success in accomplishing this objective among pipeline operators. 
PHMSA believes that an ordered and structured approach to quality 
management can help pipeline operators achieve a more consistent state 
of quality and thus improve pipeline safety.
    PHMSA's pipeline safety regulations do not currently address 
process management issues such as quality management systems. Section 
192.328 requires a quality assurance plan for the construction of 
pipelines intended to operate at an alternative MAOP, but there is no 
similar requirement applicable to other pipelines. Quality assurance is 
generally considered to be an element of quality management. Important 
elements of quality management systems are their design and application 
to control (1) the equipment and materials used in new construction 
(e.g., quality verification of materials used in construction and 
replacement, post-installation quality verification), and (2) the 
contractor work product used to construct, operate, and maintain the 
pipeline system (e.g., contractor qualifications, verification of the 
quality of contractor work products).
    The ANPRM then listed questions for consideration and comment. The 
following are general comments received related to this topic as well 
as comments related to the specific questions:
General Comments for Topic M
    1. MidAmerican suggested that PHMSA work with the committees for 
ASME/ANSI B31.8 and B31.8S to address these topics more fully, if PHMSA 
believes more is needed. MidAmerican opined that a general rule 
addressing quality management systems would divert resources and 
adversely affect safety, if applied to this already heavily-regulated 
industry.
    2. The Alaska Department of Natural Resources supported quality 
management systems and suggested that pipeline operators should apply 
such standards to their contractors.
    3. A private citizen supported quality management systems, noting 
that this is an area that would be difficult to regulate but might be 
an element in incentive programs.
    Comments submitted for questions in Topic M.
    M.1. What standards and practices are used within the pipeline 
industry to assure quality? Do gas transmission pipeline operators have 
formal QMS?
    1. INGAA opined that achieving consistent quality materials, 
construction and management is an appropriate focus for the INGAA 
Foundation, which has sponsored and will continue to sponsor workshops 
on this subject. INGAA reported that the Foundation plans to publish 
five relevant White Papers in 2012 and its Integrity Management--
Continuous Improvement team is currently working on guidelines. INGAA 
also noted that there are elements of a quality management system in 
ASME/ANSI B31.8S, already incorporated by reference, including quality 
assurance/quality control, management of change, communication and 
performance measurement, Standards, specifications, and procedures 
governing pipe and appurtenances form part of a pipeline quality 
management system. INGAA cited ISO (9001:2008/29001:2010) and API (Spec 
Q1) quality management standards as references that are available for 
operator use. INGAA further noted that API published Spec Q2 in 
December 2011. Several pipeline operators supported INGAA's comments.
    2. AGA, GPTC, Nicor, Atmos, the Texas Pipeline Association, and the 
Texas Oil & Gas Association suggested that part 192, taken as a whole, 
is essentially a quality management system. AGA provided a summary 
listing of part 192 requirements that assure quality. A number of 
additional pipeline operators supported AGA's comments.
    3. Ameren Illinois reported that it has a quality assurance program 
for pipeline construction that includes building alliances with 
excavators and other elements.
    4. Paiute and Southwest Gas reported that their practices beyond 
compliance with part 192 requirements include operator qualification 
(OQ) for construction, an internal quality assurance group, root cause 
analysis of events, and quality control verification of OQ.
    5. MidAmerican reported that it has no formal quality management 
system but applies standards to assure quality processes. In 
particular, ASME/ANSI B31.8 and B31.8S and ANSI/ISO/ASQ Q9004-2000 were 
used to guide its company quality programs. MidAmerican also has a 
contractor oversight program.
    6. An anonymous commenter opined that most operators have a quality 
management system, often incorporated into their SCADA system, to 
satisfy customers or end user requirements. The commenter suggested 
that some of these systems have only recently been modified to address 
internal corrosion mechanisms, often identified as part of operators' 
integrity management programs.
    M.2. Should PHMSA establish requirements for QMS? If so, why? If 
so, should these requirements apply to all gas transmission pipelines 
and to the complete life cycle of a pipeline system?

[[Page 20798]]

    1. INGAA, supported by a number of its pipeline operator members, 
asserted that no new requirements are appropriate at this time. INGAA 
noted that much work is ongoing in this area and it may be appropriate 
to adopt some standards (e.g., API Q1 or Q2) in the future.
    2. AGA, GPTC, the Texas Pipeline Association, the Texas Oil & Gas 
Association, Oleksa and Associates, and numerous pipeline operators 
expressed an opinion that new quality assurance requirements are not 
needed. These commenters view part 192 as quality assurance 
requirements and argue that a new programmatic requirement would not be 
beneficial.
    3. TransCanada opined that quality management systems need to be 
adopted throughout the entire industry and embraced by operators and 
contractors alike, arguing that this would provide a more consistent 
level of quality throughout the industry. TransCanada opined that the 
INGAA Foundation is the appropriate venue in which to develop 
guidelines.
    4. Northern Natural Gas opined that the existing process, which 
includes PHMSA/State inspections, is adequate.
    5. A private citizen commented that quality management systems 
should be required to improve pipeline safety, including documentation, 
investigations, validation, audits/inspections, change management, 
training, and quality/management oversight.
    6. An anonymous commenter opined that no new requirements are 
needed, arguing that most operators have such systems.
    M.3. Do gas transmission pipeline operators require their 
construction contractors to maintain and use formal QMS? Are contractor 
personnel that construct new or replacement pipelines and related 
facilities already required to read and understand the specifications 
and to participate in skills training prior to performing the work?
    1. INGAA reported that most of its members apply quality management 
principles, including requiring contractors conform to specified 
requirements, though the approach varies from operator to operator. 
INGAA acknowledged, however, that ``[t]here is room to establish a more 
structured approach to QMS for operators and construction contractors'' 
to assure more consistency. A number of pipeline operators supported 
INGAA's comments.
    2. AGA reported that transmission operators have the means to 
assure contractor work quality and that most LDC operators impose 
operator qualification (OQ) and other specific requirements on their 
construction contractors.
    3. The Texas Pipeline Association and the Texas Oil & Gas 
Association encouraged PHMSA not to adopt requirements for operators to 
train construction personnel. The associations expressed concerns over 
potential liability and their preference for a performance-based 
standard.
    4. Ameren Illinois, Atmos, and MidAmerican reported that they apply 
operator qualification (OQ) requirements on their contractors.
    5. Northern Natural Gas, Paiute, and Southwest Gas reported that 
they do not require contractors to have formal QMS but do require 
conformance to various standards.
    6. Oleksa and Associates reported its experience that operators 
require construction contractors to meet the same standards as their 
employees.
    7. GPTC, Nicor, and an anonymous commenter suggested that 
compliance with construction regulations contribute to QMS through 
requirements for specifications and inspections.
    8. NAPSR, the Texas Pipeline Association, and the Texas Oil & Gas 
Association suggested that operator qualification (OQ) requirements be 
applied to construction, since this would apply formal QMS to the full 
range of construction and operation.
    M.4. Are there any standards that exist that PHMSA could adopt or 
from which PHMSA could adapt concepts for QMS?
    1. INGAA and a number of pipeline operators suggested that several 
standards could be used as general references, including ISO 9001:2008 
(Quality Management Systems), ISO 29001:2010 (Oil and Gas) and API Spec 
Q1 (Oil and Gas). INGAA opined that compliance with these standards 
should not be required, and added that additional standards, white 
papers, and guidance are under development.
    2. The AGA, GPTC, Nicor, and Ameren Illinois opposed new 
requirements in this area. AGA opined that part 192 is already 
``saturated'' with this type of requirement. A number of additional 
pipeline operators supported AGA's comments.
    3. The NTSB recommended improvement to PHMSA's drug and alcohol 
requirements, citing their recommendations P-11-12 & 13.
    4. A private citizen suggested that, by extrapolating from the 
practices of a pipeline operator with a good safety record. The 
commenter stated that useful references include the Baldrige 
Performance Excellence Program and Quality Management Standard ISO 
9000.
    M.5. What has been the impact on cost and safety in other 
industries in which requirements for a QMS have been mandated?
    1. INGAA reported that quality management systems have been 
demonstrated to reduce risk and opined that the keys to a successful 
QMS are simplicity, empowerment, accountability and ease of 
implementation. A number of pipeline operators supported INGAA's 
comments.
    M.6. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.
Response to All Topic M Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
does not propose additional rulemaking for this topic at this time. 
PHMSA will review the comments received on the ANPRM and will consider 
them in future rulemaking.

N. Exemption of Facilities Installed Prior to the Regulations

    The ANPRM requested comments regarding proposed changes to part 192 
regulations that would eliminate provisions that exempt pipelines from 
pressure test requirements to establish MAOP. Federal pipeline safety 
regulations were first established with the initial publication of part 
192 on August 19, 1970 (35 FR 13248). Gas transmission pipelines had 
existed for many years prior to this, some dating to as early as 1920. 
Many of these older pipelines had operated safely for years at 
pressures higher than would have been allowed under the new 
regulations. It was concluded that a required reduction in the 
operating pressure of these pipelines would not have resulted in a 
material increase in safety. Therefore, a provision was included in the 
regulations (Sec.  192.619(c)) that allowed pipelines to

[[Page 20799]]

operate at the highest actual operating pressure to which they were 
subjected during the 5 years prior to July 1, 1970. The safe operation 
of these pipelines at these pressures was deemed to be evidence that 
operation could safely continue.
    Many gas transmission pipelines continue to operate in the United 
States under an MAOP established in accordance with Sec.  192.619(c). 
Some of these pipelines operate at stress levels higher than 72 percent 
specified minimum yield strength (SMYS), the highest level generally 
allowed for more modern gas transmission pipelines. Some pipelines 
operate at greater than 80 percent SMYS, the alternate MAOP allowed for 
some pipelines by regulations adopted October 17, 2008 (72 FR 62148). 
Under these regulations, operators who seek to operate their pipelines 
at up to 80 percent SMYS (in Class 1 locations) voluntarily accept 
significant additional requirements applicable to design, construction, 
and operation of their pipeline that are intended to assure quality and 
safety at these higher operating stresses. Pipelines that operate under 
an MAOP established in accordance with Sec.  192.619(c) are subject to 
none of these additional requirements.
    Part 192 also includes several provisions other than establishment 
of MAOP for which an accommodation was made in the initial part 192. 
These provisions allowed pipeline operators to use steel pipe that had 
been manufactured before 1970 and did not meet all requirements 
applicable to pipe manufactured after part 192 became effective 
(192.55); valves, fittings and components that did not contain all the 
markings required (192.63); and pipe which had not been transported 
under the standard included in the new part 192 (192.65, subject to 
additional testing requirements).
    The ANPRM then listed questions for consideration and comment. The 
following are general comments received related to this topic as well 
as comments related to the specific questions:
General Comments for Topic N
    1. INGAA and a number of pipeline operators opined that age alone 
is not an appropriate criterion for determining a pipeline's fitness 
for service. Old pipe that is well maintained operates safely and unfit 
pipe should be replaced regardless of age. INGAA suggested that fitness 
for service of pipe in HCAs should be evaluated using available 
records, if adequate, or through new testing. INGAA attached a white 
paper to its comments that described its Fitness for Service protocol. 
INGAA also cautioned that any requirement to reconfirm MAOP should be 
subject to a rigorous cost-benefit analysis, as hydrostatic testing is 
very expensive and could require outages of up to several weeks.
    2. A private citizen suggested phasing out sub-standard or systems 
that pre-date regulatory requirements where public safety is concerned, 
implying that this has been done in other areas (citing elimination of 
radium dial watches and leaking underground storage tanks as examples).
    3. A private citizen suggested that legacy facilities should be 
subject to a timetable to come into full compliance with current 
regulations, arguing that this would improve safety and knowledge of 
older facilities.
Response to General Comments for Topic N
    PHMSA appreciates the information provided by the commenters. NTSB 
recommended that regulatory exemptions be repealed. In addition, 
section 23 of the Act addressed gas transmission pipelines without 
records sufficient to validate MAOP. In response to these concerns, 
this NPRM proposes requirements for verification of maximum allowable 
operating pressure (MAOP) in new Sec.  192.624 for onshore, steel, gas 
transmission pipelines that are located in an HCA or MCA and meet any 
of the conditions in Sec.  192.624(a)(1) through (a)(3). Verification 
of MAOP includes establishing and documenting MAOP if the pipeline MAOP 
was established in accordance with Sec.  192.619(c), the grandfather 
clause. In addition, this NPRM proposes requirements for verification 
of pipeline material in accordance with new Sec.  192.607 for existing 
onshore, steel, gas transmission pipelines that are located in an HCA 
or class 3 or class 4 locations.
Comments Submitted for Questions in Topic N
    N.1. Should PHMSA repeal provisions in part 192 that allow use of 
materials manufactured prior to 1970 and that do not otherwise meet all 
requirements in part 192?
    1. INGAA, supported by several pipeline operators, suggested age, 
alone, should not be a criterion for determining fitness for service, 
noting some pre-regulation materials (e.g., seamless pipe) are as good 
as today's.
    2. AGA, GPTC, and numerous pipeline operators noted it is illogical 
to storehouse pre-1970 materials for installation now. AGA indicated 
that it thus did not understand the purpose of the ANPRM question.
    3. Iowa Utilities Board, NAPSR, Texas Pipeline Association, Texas 
Oil & Gas Association, Accufacts, Alaska Department of Natural 
Resources, Atmos, Commissioners of Wyoming County Pennsylvania, 
Professional Engineers in California Government, and an anonymous 
commenter encouraged repeal of this allowance. Some of these commenters 
would allow a specified time period for operators to come into 
compliance.
    4. Thomas Lael and MidAmerican recommended operators be allowed to 
continue use of materials that have already been placed into service, 
arguing that they have been demonstrated safe through integrity 
management.
    5. Ameren Illinois and Northern Natural Gas opposed repeal of this 
provision.
Response to Question N.1 Comments
    PHMSA appreciates the information provided by the commenters. As 
stated above, this NPRM proposes requirements for verification of MAOP 
in new Sec.  192.624 for onshore, steel, gas transmission pipelines 
that are located in an HCA or MCA and meet any of the conditions in 
Sec.  192.624(a)(1) through (a)(3). In addition, this NPRM proposes 
requirements for verification of pipeline material in accordance with 
new Sec.  192.607 for existing onshore, steel, gas transmission 
pipelines that are located in an HCA or class 3 or class 4 locations.
    N.2. Should PHMSA repeal the MAOP exemption for pre-1970 pipelines? 
Should pre-1970 pipelines that operate above 72% SMYS be allowed to 
continue to be operated at these levels without increased safety 
evaluations such as periodic pressure tests, in-line inspections, 
coating examination, CP surveys, and expanded requirements on 
interference currents and depth of cover maintenance?
    1. INGAA and a number of pipeline operators opposed repeal of this 
exemption. INGAA suggested its Fitness for Service protocol be used to 
assure continued safety of old pipe.
    2. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas 
Association and numerous pipeline operators commented that the wording 
of this question creates a false impression. There is no exemption for 
MAOP. Rather, the regulations establish requirements for determining 
MAOP and the only ``exemption'' is to a post-construction hydrostatic 
test, since the pipeline was in service at the time the regulations 
became effective.
    3. AGA, supported by several of its pipeline operator members, 
contended the appropriate method for verifying

[[Page 20800]]

MAOP of older pipelines is for PHMSA to follow Section 23 of the 
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. 
AGA opposed eliminating Sec.  192.619(c) for determining MAOP of older 
pipelines, arguing that it would cripple the nation's gas pipeline 
capacity. A number of additional pipeline operators joined AGA in 
opposing any new requirement to pressure test all older pipelines, 
arguing costs would be excessive and there would be significant 
potential to interrupt gas services. AGA included a white paper with 
its comments outlining its suggested approach to MAOP verification.
    4. Accufacts, Texas Pipeline Association, and Texas Oil & Gas 
Association opposed requiring all pre-1970 pipelines to reduce MAOP, if 
necessary, to a pressure that would impose stresses no greater than 72 
percent SMYS. Accufacts noted this pipe is still safe at its current 
operating pressure if it is managed properly, but suggested a possible 
focus on interactive threats that might make seam welds unstable.
    5. Ameren Illinois opposed modifying MAOP requirements for pre-1970 
pipelines.
    6. NAPSR, the NTSB, and Professional Engineers in California 
Government supported repeal of exemptions applying to MAOP of pre-1970 
pipelines. NAPSR added PHMSA should not allow any pipeline to operate 
at pressures above that which would impose stresses greater than 72 
percent SMYS.
    7. MidAmerican suggested use of a performance-based approach, which 
might include a fitness for service determination for pipe in Class 2, 
3, or 4 areas or HCA.
    8. Commissioners of Wyoming County Pennsylvania would support 
repeal of MAOP exemptions because pipeline infrastructure is aging and 
they see additional safety measures needed.
Response to Question N.2 Comments
    PHMSA appreciates the information provided by the commenters. As 
stated above, this NPRM proposes requirements for verification of MAOP 
in new Sec.  192.624 for onshore, steel, gas transmission pipelines 
that are located in an HCA or MCA and meet any of the conditions in 
Sec.  192.624(a)(1) through (a)(3). Verification of MAOP includes 
establishing and documenting MAOP if the pipeline segment: (1) Has 
experienced a reportable in-service incident, as defined in Sec.  
191.3, since its most recent successful subpart J pressure test, due to 
an original manufacturing-related defect, a construction-, 
installation-, or fabrication-related defect, or a cracking-related 
defect, including, but not limited to, seam cracking, girth weld 
cracking, selective seam weld corrosion, hard spot, or stress corrosion 
cracking and the pipeline segment is located in one of the following 
locations: (i) A high consequence area as defined in Sec.  192.903; 
(ii) a class 3 or class 4 location; or (iii) a moderate consequence 
area as defined in Sec.  192.3 if the pipe segment can accommodate 
inspection by means of instrumented inline inspection tools (i.e., 
``smart pigs''); (2) Pressure test records necessary to establish 
maximum allowable operating pressure per subpart J for the pipeline 
segment, including, but not limited to, records required by Sec.  
192.517(a), are not reliable, traceable, verifiable, and complete and 
the pipeline segment is located in one of the following locations: (i) 
A high consequence area as defined in Sec.  192.903; or (ii) a class 3 
or class 4 location; or (3) the pipeline segment maximum allowable 
operating pressure was established in accordance with Sec.  192.619(c) 
of this subpart before [effective date of rule] and is located in one 
of the following areas:
    (i) A high consequence area as defined in Sec.  192.903; (ii) a 
class 3 or class 4 location; or (iii) a moderate consequence area as 
defined in Sec.  192.3 if the pipe segment can accommodate inspection 
by means of instrumented inline inspection tools (i.e., ``smart 
pigs'').
    N.3. Should PHMSA take any other actions with respect to exempt 
pipelines? Should pipelines that have not been pressure tested in 
accordance with subpart J be required to be pressure tested in 
accordance with present regulations?
    1. AGA and a number of pipeline operators opposed any requirement 
to pressure test all pipelines that have not been tested in accordance 
with subpart J, arguing Congress considered and rejected this approach 
in developing the Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011. The commenters argue such a requirement would 
cripple the pipeline industry and support the alternative requirements 
included in the Act.
    2. MidAmerican suggests a focus on pipe in Class 3 or 4 areas or 
HCAs. The company suggests no new requirements are needed if records 
are complete for pipe in these areas or it has been tested to 1.25 
times MAOP. Otherwise, MidAmerican would subject such pipelines to a 
fitness for service determination.
    3. The NTSB would require all pre-1970 pipelines to be pressure 
tested, including a spike test, citing their recommendation P-11-14.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
opposed a requirement to test all pipelines not previously subject to 
subpart J tests, arguing testing per the construction codes in effect 
when the pipelines were constructed and safe operating experience since 
then is adequate assurance of suitability.
    5. Ameren Illinois reported the State of Illinois imposed pressure 
testing requirements before federal pipeline safety regulations were 
adopted in 1970.
    6. Iowa Utilities Board and Iowa Association of Municipal Utilities 
recommended any new pressure test requirement be limited to pipeline 
segments in HCA and which operate at pressures where a rupture could 
occur (generally greater than 30 percent SMYS). These commenters argued 
the serious impacts of service interruptions pressure testing would be 
necessary for testing have not been appreciated and the cost for such 
testing of other pipelines would be unjustified absent any specific 
demonstration of risk.
    7. Commissioners of Wyoming County Pennsylvania and Professional 
Engineers in California Government (PECG) would require pressure 
testing for pipelines not previously tested to subpart J requirements, 
since this would assure public safety. PECG would also require testing 
if adequate records of prior tests do not exist, noting California has 
experienced two failures to date of pipeline not adequately tested. 
PECG would also require all testing, modification, and replacement be 
observed by a certified inspector loyal to public safety interests.
    8. An anonymous commenter would require subpart J testing but would 
allow schedule flexibility.
Response to Question N.3 Comments
    PHMSA appreciates the information provided by the commenters. This 
NPRM proposes requirements for verification of MAOP in new Sec.  
192.624 for onshore, steel, gas transmission pipelines that are located 
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1) 
through (a)(3). Verification of MAOP includes establishing and 
documenting MAOP using one or more of the methods in 192.624(c)(1) 
through (c)(6). In addition, this NPRM proposes requirements for 
verification of pipeline material in new Sec.  192.607 for existing 
onshore, steel, gas transmission pipelines that are located in an HCA 
or class 3 or class 4 locations.
    N.4. If a pipeline has pipe with a vintage history of systemic 
integrity issues in areas such as longitudinal

[[Page 20801]]

weld seams or steel quality, and has not been pressure tested at or 
above 1.1 times MAOP or class location test criteria (Sec. Sec.  
192.505, 192.619 and 192.620), should this pipeline be required to be 
pressure tested in accordance with present regulations?
    1. AGA and several pipeline operators opposed requiring hydrostatic 
tests for systemic issues, arguing it could potentially affect all 
pipelines. AGA noted Congress had considered and rejected this approach 
in developing the Pipeline Safety, Regulatory Certainty, and Job 
Creation Act of 2011. AGA supports the requirements in Section 23 of 
the Act. AGA further argued hold times in subpart J are excessive since 
defects that fail will likely do so in the first 30 minutes and urged 
PHMSA not to require any special testing for pipelines operating at 
less than 30 percent SMYS since they are likely to fail by leakage 
rather than rupture.
    2. GPTC and Nicor opposed a blanket requirement for hydrostatic 
testing. They would test only in event of a demonstrated safety issue 
and only if a risk evaluation indicates testing is appropriate. For 
distribution operators, these commenters would treat any safety issues 
in distribution integrity management programs.
    3. Atmos would not require pressure testing for systemic issues, 
arguing these are addressed adequately by subpart O.
    4. Accufacts would require testing, focusing first on pipe in HCAs, 
at pressures greater than 1.1 times MAOP. Accufacts understands some 
operators are arguing for a 1.1 x MAOP test pressure and considers that 
to be insufficient.
    5. MidAmerican would allow a risk-based alternative approach for 
problem pipe.
    6. Texas Pipeline Association and Texas Oil & Gas Association would 
require assessments appropriate to a specific threat rather than a 
blanket requirement for pressure testing.
    7. An anonymous commenter supported pressure testing for pipe 
subject to systemic issues.
Response to Question N.4 Comments
    PHMSA appreciates the information provided by the commenters. This 
NPRM proposes requirements for verification of MAOP in new Sec.  
192.624 for onshore, steel, gas transmission pipelines that are located 
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1) 
through (a)(3).
    N.5. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

O. Modifying the Regulation of Gas Gathering Lines

    The ANPRM requested comments regarding modifying the regulations 
relative to gas gathering lines. In March 2006, PHMSA issued new safety 
requirements for ``regulated onshore gathering lines.'' \38\ Those 
requirements established a new method for determining if a pipeline is 
an onshore gathering line, divided regulated onshore gas gathering 
lines into two risk-based categories (Type A and Type B), and subjected 
such lines to certain safety standards.
---------------------------------------------------------------------------

    \38\ 71 FR 13289 (March 15, 2006).
---------------------------------------------------------------------------

    The 2006 rule defined onshore gas gathering lines based on the 
provisions in American Petroleum Institute Recommended Practice 80, 
``Guidelines for the Definition of Onshore Gas Gathering Lines,'' (API 
RP 80), a consensus industry standard incorporated by reference. 
Additional regulatory requirements for determining the beginning and 
endpoints of gathering, modifying the application of API RP 80, were 
also imposed to improve clarity and consistency in their application.
    In practice, however, the use of API RP 80, even as modified by the 
additional regulations, is difficult for operators to apply 
consistently to complex gathering system configurations. Enforcement of 
the current requirements has been hampered by the conflicting and 
ambiguous language of API RP 80, a complex standard that can produce 
multiple classifications for the same pipeline system, which can lead 
to the potential misapplication of the incidental gathering line 
designation under that standard. In addition, recent developments in 
the field of gas exploration and production, such as shale gas, 
indicate that the existing framework for regulating gas gathering lines 
may need to be expanded. Gathering lines are being constructed to 
transport ``shale'' gas that range from 4 to 36 inches in diameter with 
MAOPs up to 1480 psig, far exceeding the historical operating 
parameters (pressure and diameter). The risks considered during the 
development of the 2006 rule did not foresee gathering lines of these 
diameters and pressures.
    Currently, according to 2011 annual reports submitted by pipeline 
operators, PHMSA only regulates about 8845 miles of Type A gathering 
lines, 5178 miles of Type B gathering lines, and about 6258 miles of 
offshore gathering lines, for a total of approximately 20,281 miles of 
regulated gas gathering pipelines. Gas gathering lines are currently 
not regulated if they are in Class 1 locations. Current estimates also 
indicate that there are approximately 132,500 miles of Type A gas 
gathering lines located in Class 1 areas (of which approximately 61,000 
miles are estimated to be 8-inch diameter or greater), and 
approximately 106,000 miles of Type B gas gathering lines located in 
Class 1 areas. Also, there are approximately 2,300 miles of Type B gas 
gathering lines located in Class 2 areas, some of which may not be 
regulated in accordance with Sec.  192.8(b)(2).
    The ANPRM then listed questions for consideration and comment. The 
following are general comments received related to this topic as well 
as comments related to the specific questions:
General Comments for Topic O
    1. Gas Processors Association (GPA) recommended PHMSA complete the 
study required by Section 21 of the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 before proposing any 
substantive regulations regarding gathering lines. The Association sees 
this as an essential pre-requisite and indicated it would establish a 
working group to work with PHMSA on the study. Following the study, GPA 
would then have PHMSA begin any rulemaking process with another ANPRM, 
focused on the issues to be addressed in changing regulation of 
gathering lines. Independent Petroleum Association of America, American 
Petroleum Institute, Oklahoma Independent Petroleum Association, and 
Chevron agreed any change to gathering line regulations before the 
required report to Congress would be inconsistent with the Act.
    2. Independent Petroleum Association of America, American Petroleum 
Institute, Oklahoma Independent Petroleum Association, and Chevron 
argued no change in the gathering line regulatory regime is justified. 
IPAA and API argued gathering lines can be regulated based only on 
actual, vs.

[[Page 20802]]

speculative, risk, and that any change without such demonstrated risk 
would be arbitrary, capricious, and contrary to law.
    3. Atmos would require new gathering lines operating above 20 
percent SMYS to meet requirements in Sec.  192.9(c), and those below 20 
percent SMYS Sec.  192.9(d). These paragraphs are, respectively, 
requirements applicable to Type A and Type B gathering lines. The 
``type'' of a gathering line is established in accordance with 
requirements in Sec.  192.8, and is based on the pipe material and MAOP 
of the line. Atmos argued, however, that class location changes over 
time and determining applicable requirements for new gathering lines 
based on stress levels would provide for public safety without the 
problems or confusion that could result from subsequent class location 
changes.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
suggested PHMSA treat gathering lines under a separate docket and 
collect data under the current regulatory regime before making any 
changes. The associations suggested a delay in rulemaking of 3 to 5 
years to accumulate data from recently-promulgated changes in reporting 
requirements. The associations argued changes made without gathering 
and reviewing that data could be found unnecessary and would divert 
resources from higher risk needs. Atmos agreed any rulemaking 
concerning gathering lines should be conducted under a separate docket 
due to the complexity of the issues involved.
    5. Dominion East Ohio Gas argued it is too soon for wholesale 
changes to the new federal regulations applicable to gas gathering 
lines. The company suggested one proposed change would be to consider 
``Incidental Gathering'' as defined in API RP 80.
    6. NAPSR and Commissioners of Wyoming County Pennsylvania suggested 
PHMSA assert regulatory authority beginning at the wellhead or first 
metering point. They argued the regulatory gap that results from 
excluding production facilities from regulation produces risks, 
especially in areas where high-pressure wells are being drilled in 
urban areas. NAPSR further stated that PHMSA should consider short 
sections of pipeline downstream of processing, compression, and similar 
equipment to be a continuation of gathering. The functional name of a 
segment of pipeline is not important, i.e., production, gathering, 
transmission. All pipelines should be treated the same in terms of 
safety from the well head to the city gate.
    7. Commissioners of Wyoming County Pennsylvania recommended PHMSA 
regulate gathering lines in Class 1 areas. The Commissioners noted many 
new gathering lines, some operating at high pressures, are being 
constructed in Class 1 areas of the Marcellus Shale Region, and 
regulation of these lines is necessary to ensure public safety. The 
Commissioners noted Pennsylvania law gives the state's public utilities 
commission authority to regulate pipelines but requires that they be no 
more stringent than federal regulations.
    8. The League of Women Voters of Pennsylvania would regulate 
gathering lines in the same manner as transmission and would further 
require that gas in pipelines of both types be odorized.
    9. Pipeline Safety Trust would have PHMSA assure gathering lines 
are displayed on the National Pipeline Mapping System.
Response to General Comments for Topic O
    PHMSA appreciates the information provided by the commenters. The 
commenters are correct that the Act required several actions related to 
gas gathering lines including a requirement that a study to be 
conducted prior to issuing new rules. We would note, however, that 
PHMSA is only proceeding with the issuance of an NPRM proposing 
expanded requirements and needed clarity with regard to issues that had 
been identified prior to enactment of the Act. The study has been 
completed and submitted to Congress and placed on the docket. PHMSA 
invites public comment on the study, which will inform the final rule. 
In addition, recent developments in the field of gas exploration and 
production, such as shale gas, indicate that the existing framework for 
regulating gas gathering lines may need to be expanded. Gathering lines 
are being constructed to transport ``shale'' gas that range from 4 to 
36 inches in diameter with MAOPs up to 1,480 psig, far exceeding the 
historical operating parameters of such lines.
    Currently, according to 2011 annual reports submitted by pipeline 
operators, PHMSA only regulates about 8845 miles of Type A gathering 
lines, 5,178 miles of Type B gathering lines, and about 6,258 miles of 
offshore gathering lines, for a total of approximately 20,281 miles of 
regulated gas gathering pipelines. Gas gathering lines are currently 
not regulated if they are in Class 1 locations. Current estimates also 
indicate that there are approximately 132,500 miles of Type A gas 
gathering lines located in Class 1 areas, and approximately 106,000 
miles of Type B gas gathering lines located in Class 1 areas. Also, 
there are approximately 2,300 miles of Type B gas gathering lines 
located in Class 2 areas, some of which may not be regulated in 
accordance with Sec.  192.8(b)(2).
    Moreover, enforcement of the current requirements has been hampered 
by the conflicting and ambiguous language of API RP 80, a complex 
standard that can produce multiple classifications for the same 
pipeline system because numerous factors are involved, including the 
locations of treatment facilities, processing plants, and compressors, 
the relative spacing of production fields, and the commingling of gas. 
This can lead to the potential misapplication of the incidental 
gathering line designation under that standard.
    In this NPRM, PHMSA proposes to extend existing requirements for 
Type B gathering lines to Type A gathering lines in Class 1 locations, 
if the nominal diameter is 8'' or greater.
    Comments submitted for questions in Topic O.
    O.1. Should PHMSA amend 49 CFR part 191 to require the submission 
of annual, incident, and safety-related conditions reports by the 
operators of all gathering lines?
    1. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas 
Association, and several pipeline operators opposed requiring annual 
reports for unregulated gas gathering pipelines, arguing such a 
requirement would be unduly burdensome with no safety benefit. These 
commenters agreed incident reports for unregulated gathering lines 
could be useful as a means to determine the effectiveness of safety 
practices on these pipelines.
    2. Gas Producers Association opposed expanding reporting 
requirements to Class 1 gathering pipelines. The Association noted 
gathering lines in other class locations are currently subject to 
reporting requirements and suggested there were other means for PHMSA 
to collect data on Class 1 lines without requiring burdensome 
reporting. In the specific case of safety-related condition reports, 
the Association argued requiring reporting is clearly premature, 
because the purpose of these reports is to highlight problems in which 
PHMSA may elect to become involved and PHMSA presently does not 
regulate these pipelines.
    3. Texas Pipeline Association and Texas Oil & Gas Association would 
support requiring incidents to be reported for all gathering pipelines 
as a first step in collecting data to determine whether other changes 
are needed.

[[Page 20803]]

    4. Atmos would support limited reporting for Class 1 gathering 
lines, to include incidents and total mileage.
    5. NAPSR, Alaska Department of Natural Resources, Pipeline Safety 
Trust, and Commissioners of Wyoming County Pennsylvania would require 
operators of Class 1 gathering pipelines to submit reports, because 
these pipelines can affect public safety and should be held 
accountable.
Response to Question O.1 Comments
    PHMSA appreciates the information provided by the commenters. The 
comments provide varied support for requiring submission of annual, 
incident, and safety-related conditions reports by the operators of all 
gathering lines. PHMSA believes these reports would provide valuable 
information, combined with the results of the congressionally required 
study, to support evaluation of the effectiveness of safety practices 
on these pipelines and determination of any needed additional 
requirements beyond those proposed in this NPRM. Accordingly, PHMSA 
proposes to delete the exemption for reporting requirements for 
operators of unregulated onshore gas gathering lines.
    O.2. Should PHMSA amend 49 CFR part 192 to include a new definition 
for the term ``gathering line''?
    1. AGA and several pipeline operators opposed a change to the 
definition of gathering lines, noting API RP-80, with restrictions as 
specified in current regulations, is a good working definition.
    2. Independent Petroleum Association of America, American Petroleum 
Institute, Oklahoma Independent Petroleum Association, Atmos, and 
Chevron argued that API RP 80, as currently specified, is the 
appropriate means for defining gathering lines. They argued it is based 
on a pipeline's function rather than its location and changes could 
infringe on production facilities, regulation of which is precluded by 
statute.
    3. Gas Processors Association opposed changing the definition of 
gathering line or extending regulation to lines in Class 1 areas. The 
Association noted excluding Class 1 lines from regulation is risk-based 
and expressed its interest in continuing the risk-based approach to 
regulation represented by the 2006 rule.
    4. NAPSR, GPTC, Accufacts, Thomas Lael, and Nicor supported 
simplifying the definition of gathering lines. These commenters noted 
that API RP-80 is confusing. One commenter referred to its application 
as a ``nightmare.'' The definition in Texas regulations was suggested 
as one possible model.
    5. Oklahoma Independent Petroleum Association strongly opposed 
changes to the definitions of gathering line or production facilities.
    6. Texas Pipeline Association and Texas Oil & Gas Association would 
not change the definition of gathering lines at this time, arguing data 
gathering, a necessary first step, is not yet complete.
    7. The State of Washington Citizens Advisory Committee and a 
private citizen urged changes to the definitions of gathering, 
transmission, and distribution pipelines, arguing that the current 
definitions are confusing and employ circular logic.
    8. Pipeline Safety Trust would revise the definition of gathering 
in a manner that does not allow operators to choose whether their 
pipeline is gathering or not on the basis of where they decide to 
install equipment. PST noted there is significant overlap among 
pipeline types in size, operating pressure, and attendant risks.
    9. Alaska Department of Natural Resources and Commissioners of 
Wyoming County Pennsylvania urged a revision to the definition of 
gathering lines, in light of shale gas development which, the 
commenters contended, produces risks approximately equivalent to those 
from transmission pipelines.
Response to Question O.2 Comments
    PHMSA appreciates the information provided by the commenters. 
Industry commenters opposed a change to the definition of gathering 
lines, whereas NAPSR and other commenters supported revision of the 
definition of gathering lines and classified API RP-80 as confusing. As 
discussed above, PHMSA believes revision of the definition of gathering 
lines is needed and also proposes a new definition for onshore 
production facility/operation. In addition, see response to question 
O.3 comments.
    O.3. Are there any difficulties in applying the definitions 
contained in RP 80? If so, please explain.
    1. Independent Petroleum Association of America, American Petroleum 
Institute, Oklahoma Independent Petroleum Association, and Chevron were 
emphatic in declaring there are no difficulties in applying API RP-80. 
IPAA and API noted that significant difficulties among gathering lines 
made RP-80 difficult to develop.
    2. AGA and a number of pipeline operators reported RP-80 is clear 
and there are no difficulties with its application.
    3. Gas Processors Association would retain the RP-80 definition, at 
least until the study required by the Act is completed. GPA 
acknowledged that application of RP-80 has been difficult, but stated 
that it has been difficult to craft a simpler definition.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
reported application of RP-80 has been challenging. The associations 
opined this has resulted from complexities in gathering pipeline 
systems and confusion caused by PHMSA guidance and interpretations.
    5. Accufacts, NAPSR, GPTC, and Nicor commented RP-80 is too 
complex, not understandable to the public, and subject to misuse by 
operators.
Response to Question O.3 Comments
    PHMSA appreciates the information provided by the commenters. 
Industry commenters stated there are no difficulties in applying the 
definitions contained in API RP 80, whereas Accufacts, NAPSR and other 
commenters contend that API RP 80 is too complex, not understandable, 
and subject to misuse. PHMSA enforcement of the current requirements 
has been hampered by the conflicting and ambiguous language of API RP 
80, which is complex and can produce multiple classifications for the 
same pipeline system. In the 2006 rulemaking which incorporated by 
reference the API RP 80, PHMSA expressed reservations concerning the 
ability to effectively and consistently apply the document as written, 
echoing NAPSR's comments at the time. Additionally, in 2006, PHMSA 
imposed limiting regulatory language in part 192 in an attempt to 
curtail the potential for misapplication of the language contained in 
RP-80. These limitations and their intended application were discussed 
in great detail in the Supplemental Notice of Proposed Rulemaking 
[Docket No. RSPA-1998-4868; Notice 5]. Because of the ambiguous 
language and terminology in the RP-80, e.g. separators are defined for 
both production and gathering almost verbatim, experience has shown 
that facilities are being classified as production much further 
downstream than was ever intended. The application of ``incidental 
gathering'' as used in API RP-80 has not been applied as intended in 
some cases. Several recent interpretations letters have been issued by 
PHMSA on this topic including an expressed intent to clarify the issue 
in future rulemaking. Therefore, PHMSA believes revision of the 
definition of gathering lines is needed and proposes

[[Page 20804]]

deleting the use of API RP 80 as the basis for determining regulated 
gathering lines and would establish the new definition for onshore 
production facility/operation and a revised definition for gathering 
line as the basis for determining the beginning and endpoints of each 
gathering line.
    O.4. Should PHMSA consider establishing a new, risk-based regime of 
safety requirements for large-diameter, high-pressure gas gathering 
lines in rural locations? If so, what requirements should be imposed?
    1. Commissioners of Wyoming County Pennsylvania and 24 private 
citizens encouraged PHMSA to regulate gathering lines in Class 1 
locations. The commenters noted many such pipelines will exist in shale 
gas areas, many of them large-diameter and operating at high pressures, 
and contended these pipelines currently are being ignored by federal 
and state regulators. They noted the pipeline that ruptured causing the 
San Bruno accident was operated at a pressure considerably lower than 
some gathering lines in shale gas areas.
    2. AGA, GPTC, and a number of pipeline operators argued no new 
requirements are needed and the effectiveness of the 2006 changes to 
regulation needs to be reviewed first, in accordance with the Act.
    3. Gas Processors Association, Texas Pipeline Association, and 
Texas Oil & Gas Association contended PHMSA must gather additional data 
on Class 1 gathering lines before deciding whether to regulate them, 
arguing that only a detailed study can determine whether new 
regulations are appropriate.
    4. Oklahoma Independent Petroleum Association cautioned any 
regulatory change needs to be supported by science and a comprehensive 
cost-benefit analysis.
    5. Independent Petroleum Association of America, American Petroleum 
Institute, Oklahoma Independent Petroleum Association, and Chevron 
argued any change in the regulatory regime for gathering lines is 
unjustified. The commenters contended such lines only operate at high 
pressures when new, that pressure decreases as wells deplete, and that 
the record shows these lines are safe.
    6. A private citizen who operates an outdoor gear supply business 
in a shale gas region argued reduced use of recreational areas, caused 
by concerns over nearby pipelines, will adversely impact his and 
similar businesses.
    7. Alaska Department of Natural Resources would establish risk-
based safety requirements for gathering pipelines.
    8. NAPSR would establish new, prescriptive requirements for large-
diameter, high-pressure gathering lines.
    9. Pipeline Safety Trust argued the composition of gas carried in 
many gathering lines leads to increased risk of corrosion and 
additional corrosion and testing requirements should thus be 
considered.
    10. A private citizen, arguing for regulation of Class 1 gathering 
lines, noted experience has shown Class 1 locations change to Class 2 
or 3 locations while the pipeline remains unchanged and, the commenter 
contended, unsafe.
    11. Pipeline Safety Trust, Accufacts, and NAPSR would regulate 
gathering lines the same as transmission pipelines. PST would include 
integrity management requirements for lines operating at greater than 
20 percent SMYS. NAPSR would impose IM if greater than 30 percent SMYS.
    12. ITT Exelis Geospatial Systems contended that safety criteria 
applicable to a pipeline should be based on the specifications of the 
line.
Response to Question O.4 Comments
    PHMSA appreciates the information provided by the commenters. The 
comments provide varied opinions for establishing new, risk-based 
safety requirements for gas gathering lines in rural locations. Several 
comments recommended PHMSA gather additional data on gathering lines 
before deciding to issue revised regulations. PHMSA believes rulemaking 
should proceed now to address the identified issues with regulation of 
gathering lines. Therefore, PHMSA proposes to extend existing 
requirements for Type B gathering lines to Type A gathering lines in 
Class 1 locations, if the nominal diameter is 8'' or greater. Integrity 
management requirements would not be applied to gathering lines at this 
time.
    O.5. Should PHMSA consider short sections of pipeline downstream of 
processing, compression, and similar equipment to be a continuation of 
gathering? If so, what are the appropriate risk factors that should be 
considered in defining the scope of that limitation (e.g., doesn't 
leave the operator's property, not longer than 1000 feet, crosses no 
public rights of way)?
    1. The AGA, the GPTC, and a number of pipeline operators suggested 
that the piping mentioned in O.5 be considered as gathering. The 
commenters contended that this is clearly ``incidental gathering'' in 
API RP-80, particularly if below 20 percent SMYS, and that some 
agencies are presently treating this pipeline inappropriately as 
transmission pipeline.
    2. Oleksa and Associates contended that the types of pipeline 
described in the question are ``incidental gathering.'' Oleksa argued 
that the length of these pipeline sections should not be the 
determining factor in their definition but, rather, risk elements and 
public safety impact should be afforded more importance.
    3. The Gas Processors Association, the Texas Pipeline Association, 
and the Texas Oil & Gas Association would continue to treat these types 
of pipelines as gathering. They argued that this reflects the practical 
realities in the field regarding the ability to locate gathering-
related equipment. GPA urged PHMSA to retain the concept of incidental 
gathering in any future change to the regulations, arguing this would 
continue a consistent regulatory approach to gathering pipelines.
    4. The Independent Petroleum Association of America, the American 
Petroleum Institute, the Oklahoma Independent Petroleum Association, 
and Chevron contended that the safety record in the Barnett Shale area 
demonstrates further regulation of downstream pipelines and compression 
is not needed.
    5. Commissioners of Wyoming County Pennsylvania would treat 
gathering lines as transmission lines, arguing that this would preclude 
the need to answer any of these questions.
    6. The Delaware Solid Waste Authority (DSWA) argued for the 
continued treatment of the listed pipeline sections as part of 
gathering for landfill gas operations. DSWA noted that landfills may 
use intermediate compression to improve collection efficiency and may 
have pipe at pressure leading to flares etc.
    7. Waste Management contended that piping that is an active part of 
a landfill gas collection and control system should be exempt from 
regulation as this piping is generally on landfill property and poses 
no risk to the public.
    8. The National Solid Waste Management Association and Waste 
Management supported PHMSA's interpretation that pipelines operating at 
vacuum, such as landfill systems up to the compressor/blower should be 
unregulated.
Response to Question O.5 Comments
    PHMSA appreciates the information provided by the commenters. See 
PHMSA's response to Question O.3, above.
    O.6. Should PHMSA consider adopting specific requirements for 
pipelines associated with landfill gas

[[Page 20805]]

systems? If so, what regulations should be adopted and why? Should 
PHMSA consider adding regulations to address the risks associated with 
landfill gas that contains higher concentrations of hydrogen sulfide 
and/or carbon dioxide?
    1. The AGA, the GPTC, and a number of pipeline operators contended 
that RP-80 makes clear that these pipelines are production piping and 
therefore regulation is prohibited. In addition, they argued that risk 
doesn't justify regulating these lines; the situation is similar to 
production and is already managed well. They also noted that landfill 
systems are generally constructed with non-corrosive materials. The 
commenters agreed that piping from landfills to transmission or 
distribution pipelines is gathering and should be regulated.
    2. Oleksa and Associates contended that landfill pipelines are 
distribution pipelines, if they carry gas to end use customers.
    3. The APGA argued that new requirements are appropriate, as 
landfill gas is different from natural gas. The APGA contended that 
application of current regulations often produces absurd results. APGA 
would add new requirements applicable to systems with high 
concentrations of hydrogen sulfide and allow systems with low 
concentrations to use current requirements.
    4. The Delaware Solid Waste Authority argued that no new 
requirements are needed, because these systems operate at low pressures 
and existing requirements are sufficient.
    5. NAPSR encouraged that PHMSA establish jurisdiction over and 
requirements for landfill gas systems, arguing that many operate as 
distribution pipelines. NAPSR also recommended that PHMSA develop 
requirements for odorizing landfill gas, since normal methods cannot be 
used.
    6. The National Solid Waste Management Association and Waste 
Management argued that landfill gas lines under the control of a 
landfill operator or gas developer should remain unregulated because 
they pose minimal risk. They also contended that lines delivering 
landfill gas to distant users should also remain unregulated because 
they are mostly buried, are generally constructed of plastic pipe, and 
pose low risk due to low pressure, their dedicated nature, and lack of 
interconnects.
    7. The National Solid Waste Management Association (NSWMA) noted 
that these pipelines are already regulated by the EPA and the states 
and argued that additional regulation would confer limited additional 
benefits. NSWMA argued that no requirements are needed to address 
internal corrosion, because these pipeline systems are generally 
constructed of plastic pipe and corrosive gas constituents are limited 
to prevent destruction of gas processing equipment. NSWMA suggested 
that PHMSA work with the EPA to obtain data on the landfill experience 
needed to support any future decision to regulate in this area.
    8. Oleksa and Associates and the Delaware Solid Waste Authority 
would have PHMSA modify the regulations to clarify that pipe downstream 
of intermediate compression is unregulated, even if at pressure. They 
argued that the EPA has regulated such pipelines successfully and there 
is no safety case for applying part 192. DSWA further notes that most 
landfill pipeline is constructed of plastic pipe and not subject to 
internal corrosion.
    9. Oleksa and Associates, the GPTC, Nicor, Waste Management, and 
the Delaware Solid Waste Authority would exempt landfill gas systems 
from requirements for odorization and odor sampling. They argued that 
there is a strong odor inherent to landfill gas, the sampling of which 
is not practical.
Response to Question O.6 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
is not proposing rulemaking to address landfill gas systems at this 
time, but would note that a pipeline that transports landfill gas away 
from the landfill facility to another destination is transporting gas. 
PHMSA will consider comments on this aspect of Topic O in the future.
    O.7. Internal corrosion is an elevated threat to gathering systems 
due to the composition of the gas transported. Should PHMSA enhance its 
requirements for internal corrosion control for gathering pipelines? 
Should this include required cleaning on a periodic basis?
    1. AGA, GPTC, and a number of pipeline operators commented that new 
requirements are not needed. They argued existing part 192 requirements 
are adequate for internal corrosion protection and unregulated 
gathering lines are rural and pose little risk.
    2. AGA and a number of pipeline operators opposed a requirement for 
periodic cleaning of gathering lines. They noted existing lines are not 
configured to accommodate cleaning pigs and retrofitting them would be 
a major cost with no safety benefit.
    3. Gas Producers Association noted internal corrosion is only one 
of many threats, existing regulations are adequate, and thus no new 
requirements are needed.
    4. Texas Pipeline Association and Texas Oil & Gas Association 
opposed establishing internal corrosion requirements for gathering 
pipelines. The associations noted risk from IC is not prevalent for 
many gathering pipelines and suggested the need to collect data (e.g., 
incidents) to determine whether new requirements are needed.
    5. Accufacts would require, as a minimum, use of cleaning pigs and 
analysis of removed materials.
    6. NAPSR, Alaska Department of Natural Resources, and Commissioners 
of Wyoming County Pennsylvania would enhance internal corrosion 
requirements and require periodic cleaning.
Response to Question O.7 Comments
    PHMSA appreciates the information provided by the commenters. The 
majority of comments do not support enhancement of requirements for 
internal corrosion control for gathering pipelines. PHMSA is not 
proposing rulemaking specifically to address the need for additional 
internal corrosion requirements for gathering lines at this time. 
However, the proposed requirements in subpart I applicable to 
transmission lines; except the requirements in Sec. Sec.  192.461(f), 
192.465(f), 192.473(c) and 192.478, would be applicable to regulated 
Type A onshore gathering lines.
    O.8. Should PHMSA apply its Gas Integrity Management Requirements 
to onshore gas gathering lines? If so, to what extent should those 
regulations be applied and why?
    1. The AGA and several pipeline operators suggested that PHMSA 
consider applying some IM requirements to Type A gathering lines, since 
these lines represent conditions and risks similar to transmission 
pipelines. They consider IM inappropriate for Type B gathering lines, 
since these lines pose low risk and operate at hoop stresses similar to 
distribution pipelines.
    2. The Gas Producers Association, the Texas Pipeline Association, 
the Texas Oil & Gas Association, and Atmos argued that it would be 
inappropriate to apply integrity management requirements to gathering 
pipelines. They noted that IM is a risk-based approach and that there 
is no evidence that gathering pipelines pose a risk that justifies 
application of IM.
    3. The GPTC and Nicor opined that extending some aspects of gas 
transmission IM to non-rural, metallic

[[Page 20806]]

Type A gathering lines could provide enhanced protection to the public, 
since the operation and risk of these pipelines is similar to 
transmission pipelines. They cautioned, however, that the costs to 
impose IM on gathering pipelines would be significant. They considered 
IM inappropriate for Type B gathering lines since these lines are, by 
definition, of lower pressure and lower risk.
    4. The Commissioners of Wyoming County Pennsylvania would apply IM 
to all onshore gathering pipelines. They would also apply requirements 
applicable to Class 2 transmission pipelines to Class 1 gathering 
pipelines, arguing that Class 1 areas will grow and class location will 
change.
    5. Accufacts and the Alaska Department of Natural Resources would 
apply IM to gathering lines. Accufacts suggested an initial focus on 
large-diameter, high-pressure lines, since these lines are subject to 
failure by rupture.
Response to Question O.8 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA 
does not propose rulemaking to apply integrity management requirements 
to gathering lines at this time.
    O.9. If commenters suggest modification to the existing regulatory 
requirements, PHMSA requests that commenters be as specific as 
possible. In addition, PHMSA requests commenters to provide information 
and supporting data related to:
     The potential costs of modifying the existing regulatory 
requirements.
     The potential quantifiable safety and societal benefits of 
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the 
existing regulatory requirements.
     The potential environmental impacts of modifying the 
existing regulatory requirements.
    No comments were received in response to this question.

IV. Other Proposals

    Inspection of Pipelines Following Extreme Weather Events.
    Pipeline regulation prescribes requirements for the surveillance 
and periodic patrolling of the pipeline to observe surface conditions 
on and adjacent to the transmission line right-of-way for indications 
of leaks, construction activity, and other factors affecting safety and 
operation, including unusual operating and maintenance conditions. The 
probable cause of the 2011 hazardous liquid pipeline accident resulting 
in a crude oil spill into the Yellowstone River near Laurel, Montana, 
is scouring at a river crossing due to flooding. This is a recent 
example of extreme weather that resulted in a pipeline incident. PHMSA 
has determined that additional regulations are needed to require, and 
establish standards for, the inspection of the pipeline and right-of-
way for ``other factors affecting safety and operation'' following an 
extreme weather event such as a hurricane or flood, landslide, an 
earthquake, a natural disaster, or other similar event. The proposed 
rule would add a new paragraph (c) to section 192.613 to require such 
inspections, specify the timeframe in which such inspections should 
commence, and specify the appropriate remedial actions that must be 
taken to ensure safe pipeline operations. The new paragraph (c) would 
apply to onshore pipelines and their rights-of-way.
    Notification for 7-Year Reassessment Interval Extension.
    Section 5 of the Act identifies a technical correction amending 
Section 60109(c)(3)(B) of Title 49 of the United States Code to allow 
the Secretary of Transportation to extend the 7-year reassessment 
interval for an additional 6 months if the operator submits written 
notice to the Secretary justifying the need for the extension. PHMSA 
proposes to codify this statutory requirement.
    Reporting Exceedances of Maximum Allowable Operating Pressure.
    Section 23 of the Act requires operators to report each exceedance 
of the maximum allowable operating pressure (MAOP) that exceeds the 
margin (build-up) allowed for operation of pressure-limiting or control 
devices. PHMSA proposes to codify this statutory requirement.
    Consideration of Seismicity.
    Section 29 of the Act states that in identifying and evaluating all 
potential threats to each pipeline segment, an operator of a pipeline 
facility must consider the seismicity of the area. PHMSA proposes to 
codify this statutory requirement to explicitly reference seismicity 
for data gathering and integration, threat identification, and 
implementation of preventive and mitigative measures.
    Safety Features for In-line Inspection (ILI), Scraper, and Sphere 
Facilities.
    PHMSA is proposing to add explicit requirements for safety features 
on launchers and receivers associated with ILI, scraper and sphere 
facilities.
    Consensus Standards for Pipeline Assessments.
    PHMSA is proposing to incorporate by reference consensus standards 
for assessing the physical condition of in-service pipelines using in-
line inspection, internal corrosion direct assessment, and stress 
corrosion cracking direct assessment.

V. Section-by-Section Analysis

    Sec.  191.1 Scope.
    Section 191.1 prescribes requirements for the reporting of 
incidents, safety-related conditions, and annual pipeline summary data 
by operators of gas pipeline facilities. Currently, onshore gas 
gathering pipelines are exempt from reporting, as specified in 
paragraph (b)(4) of this section. In March 2012, the Government 
Accountability Office (GAO) issued a report (GAO-12-388) that contained 
a recommendation for DOT to collect data on federally unregulated 
hazardous liquid and gas gathering pipelines. PHMSA has determined that 
the statute requires the collection of additional information about 
gathering lines and that these reports and the congressionally required 
study support evaluation of the effectiveness of safety practices on 
these pipelines. Furthermore, PHMSA has inquired into whether any 
additional requirements are needed beyond those proposed in this NPRM. 
Accordingly, the proposed rule would repeal the exemption for reporting 
requirements for operators of unregulated onshore gas gathering lines 
by deleting Sec.  191.1(b)(4), adding a new Sec.  191.1(c), and making 
other conforming editorial amendments. In addition, Section 23 of the 
Act requires PHMSA to promulgate rules that require operators to report 
each exceedance of the maximum allowable operating pressure (MAOP) that 
exceeds the margin (build-up) allowed for operation of pressure-
limiting or control devices. The proposed rule would amend 191.1 to 
include MAOP exceedances within the scope of part 191.
    Sec.  191.23 Reporting safety-related conditions.
    Section 23 of the Act requires operators to report each exceedance 
of the maximum allowable operating pressure (MAOP) that exceeds the 
margin (build-up) allowed for operation of pressure-limiting or control 
devices. On December 21, 2012, PHMSA published advisory bulletin ADB-
2012-11, which advised operators of their responsibility under Section 
23 of the Act to report such exceedances. PHMSA proposes to revise 
Sec.  191.23 to codify this requirement.
    Sec.  191.25 Filing safety-related condition reports.
    Section 23 of the Act requires operators to report each exceedance 
of the maximum allowable operating pressure (MAOP) that exceeds the

[[Page 20807]]

margin (build-up) allowed for operation of pressure-limiting or control 
devices. As described above, PHMSA proposes to revise Sec.  191.23 to 
codify this requirement. Section 191.25 would also be revised to 
provide consistent procedure, format, and structure for filing of such 
reports by all operators.
    Sec.  192.3 Definitions.
    Section 192.3 provides definitions for various terms used 
throughout part 192. In support of other regulations proposed in this 
NPRM, PHMSA is proposing to amend the definitions of ``Electrical 
survey,'' ``(Onshore) gathering line,'' and ``Transmission line,'' and 
add new definitions for ``Close interval survey,'' ``Distribution 
center, '' ``Dry gas or dry natural gas,'' ``Gas processing plant,'' 
``Gas treatment facility,'' ``Hard spot,'' ``In-line inspection 
(ILI),'' ``In-line inspection tool or instrumented internal inspection 
device,'' ``Legacy construction technique,'' ``Legacy pipe,'' 
``Moderate consequence area,'' ``Modern pipe,'' ``Occupied site,'' 
``Onshore production facility or onshore production operation,'' 
``Significant Seam Cracking,'' ``Significant Stress Corrosion 
Cracking,'' and ``Wrinkle bend.'' These changes will define these terms 
as used in the proposed changes to part 192. Many of the terms (such as 
in-line inspection, dry gas, hard spot, etc.) clarify technical 
definitions of terms used in part 192 or proposed in this rulemaking.
    The revised definition for ``(Onshore) gathering line,'' and the 
new definitions for ``Gas processing plant,'' ``Gas treatment 
facility,'' and ``Onshore production facility or onshore production 
operation,'' are necessary because of ambiguous language and 
terminology in the current definition of regulated gas gathering lines, 
which invoke by reference API RP-80. The application of ``incidental 
gathering'' as used in API RP-80 has not been applied as intended in 
some cases. Several recent interpretation letters have been issued by 
PHMSA on this topic including an expressed intent to clarify the issue 
in future rulemaking. Therefore, PHMSA believes revision of the 
definition of gathering lines is needed and proposes repealing the use 
of API RP 80 as the basis for determining regulated gathering lines and 
would establish the new definition for ``onshore production facility/
operation, gas treatment facility, and gas processing plant,'' and a 
revised definition for ``(onshore) gathering line'' as the basis for 
determining the beginning and endpoints of each gathering line.
    The revised definition for ``Electrical survey'' aligns with the 
amended definition recommended in a petition dated March 26, 2012, from 
the Gas Piping Technology Committee (GPTC).
    With regard to the new terms ``moderate consequence area'' or MCA, 
and ``occupied site,'' the definitions are based on the same 
methodology as ``high consequence area'' and ``identified site'' as 
defined in Sec.  192.903. Moderate consequence areas will be used to 
define the subset of non-HCA locations where integrity assessments are 
required (Sec.  192.710), where material documentation verification is 
required (Sec.  192.607), and where MAOP verification is required 
(Sec. Sec.  192.619(e) and 192.624). The criteria for determining MCA 
locations would use the same process and same definitions that are 
currently used to identify HCAs, except that the threshold for 
buildings intended for human occupancy and the threshold for persons 
that occupy other defined sites located within the potential impact 
radius would both be lowered from 20 to 5. This approach is proposed as 
a means to minimize the effort needed on the part of operators to 
identify the MCAs, since transmission operators must have already 
performed the analysis in order to have identified the HCAs or to 
verify that they have no HCAs. In response to NTSB recommendation P-14-
01, which was issued as a result of the Sissonville, West Virginia 
incident, the MCA definition would also include locations where 
interstate highways, freeways, and expressways, and other principal 4-
lane arterial roadways are located within the potential impact radius.
    With regard to the new terms ``legacy construction technique'' and 
``legacy pipe,'' the definitions are used in proposed and Sec.  192.624 
to identify pipe to which the proposed material verification and MAOP 
verification requirements would apply. The definitions are based on 
historical technical issues associated with past pipeline failures.
    Sec.  192.5 Class locations.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that an important aspect of compliance with this 
requirement is to assure that pipeline class location records are 
complete and accurate. The proposed rule would add a new paragraph 
Sec.  192.5(d) to require each operator of transmission pipelines to 
make and retain for the life of the pipeline records documenting class 
locations and demonstrating how an operator determined class locations 
in accordance with this section.
    Sec.  192.7 What documents are incorporated by reference partly or 
wholly in this part?
    Section 192.7 lists documents that are incorporated by reference in 
part 192. PHMSA proposes conforming amendments to Sec.  192.7 in the 
rule text to reflect other changes proposed in this NPRM.
    Sec.  192.8 How are onshore gathering lines and regulated onshore 
gathering lines determined?
    Section 192.8 defines the upstream and downstream endpoints of gas 
gathering pipelines. Recent developments in the field of gas 
exploration and production, such as shale gas, indicate that the 
existing framework for regulating gas gathering lines may no longer be 
appropriate. Gathering lines are being constructed to transport 
``shale'' gas that range from 4 to 36 inches in diameter with MAOPs of 
up to 1480 psig, far exceeding the historical operating parameters of 
such lines.
    Currently, according to the 2011 annual reports submitted by 
pipeline operators, PHMSA only regulates about 8,845 miles of Type A 
gathering lines, 5,178 miles of Type B gathering lines, and about 6,258 
miles of offshore gathering lines, for a total of approximately 20,281 
miles of regulated gas gathering pipelines. Gas gathering lines are 
currently not regulated if they are in Class 1 locations. Current 
estimates also indicate that there are approximately 132,500 miles of 
Type A gas gathering lines located in Class 1 areas (of which 
approximately 61,000 miles are estimated to be 8-inch diameter or 
greater), and approximately 106,000 miles of Type B gas gathering lines 
located in Class 1 areas. Also, there are approximately 2,300 miles of 
Type B gas gathering lines located in Class 2 areas, some of which may 
not be regulated in accordance with Sec.  192.8(b)(2).
    Moreover, enforcement of the current requirements has been hampered 
by the conflicting and ambiguous language of API RP 80, a complex 
standard that can produce multiple classifications for the same 
pipeline system. PHMSA has also identified a regulatory gap that 
permits the potential misapplication of the incidental gathering line 
designation under that standard. Consequently, to address these issues 
and gaps, the proposed rule would repeal the use of API RP 80 as the 
basis for determining regulated gathering lines and would establish a 
new definition for onshore production facility/operation and a

[[Page 20808]]

revised definition for gathering line as the basis for determining the 
beginning and endpoints of each gathering line. The definition of 
onshore production facility/operation includes initial preparation of 
gas for transportation at the production facility, including 
separation, lifting, stabilizing, and dehydration. Pipelines commonly 
referred to as ``farm taps'' serving residential/commercial customers 
or industrial customers are not classified as gathering, but would 
continue to be classified as transmission or distribution as defined in 
Sec.  192.3.
    Sec.  192.9 What requirements apply to gathering lines?
    Section 192.9 identifies those portions of part 192 that apply to 
regulated gas gathering lines. For the same reasons discussed under 
Sec.  192.8, above, the proposed rule would expand and clarify the 
requirements that apply to gathering lines. PHMSA proposes to extend 
existing regulatory requirements for Type B gathering lines to Type A 
gathering lines in Class 1 locations, if the nominal diameter of the 
line is 8'' or greater.
    In addition, on August 20, 2014, the GAO released a report (GAO 
Report 14-667) to address the increased risk posed by new gathering 
pipeline construction in shale development areas. GAO recommended that 
a rulemaking be pursued for gathering pipeline safety that addresses 
the risks of larger-diameter, higher-pressure gathering pipelines, 
including subjecting such pipelines to emergency response planning 
requirements that currently do not apply. Currently, Type A gathering 
lines are subject to the emergency planning requirements in Sec.  
192.615 and only include gathering lines in Class 2, 3, and 4 locations 
that have a Maximum Allowable Operating Pressure (MAOP) with a hoop 
stress of 20% or more for metallic pipe and MAOP of more than 125 psig 
for non-metallic pipe. Further, gathering lines that are located in 
Class 1 areas (e.g., rural areas) are not considered Type A gathering 
lines even if they meet the pressure criteria specified in the 
preceding sentence. PHMSA is proposing to create sub-divisions of Type 
A gathering lines (Type A, Area 1 and Type A, Area 2). The new 
designation ``Type A, Area 1 gathering lines'' would apply to currently 
regulated Type A gathering lines. The new designation ``Type A, Area 2 
gathering lines'' would apply to gathering lines with a diameter of 8-
inch or greater that meet all of the qualifying parameters for 
currently regulated Type A gathering, but are located in Class 1 
locations. PHMSA proposes to address the GAO recommendation by 
requiring the newly proposed Type A, Area 2 regulated onshore gathering 
lines, which include lines in Class 1 locations with a nominal diameter 
of 8-inch or greater, to develop procedures, training, notifications, 
and carry out emergency plans as described in Sec.  192.615, in 
addition to a limited set of other specific requirements, including 
corrosion protection and damage prevention.
    Sec.  192.13 General.
    Section 192.13 prescribes general requirements for gas pipelines. 
PHMSA has determined that safety and environmental protection would be 
improved by generally requiring operators to evaluate and mitigate 
risks during all phases of the useful life of a pipeline as an integral 
part of managing pipeline design, construction, operation, maintenance 
and integrity, including management of change. This proposed rule would 
add a new paragraph (d) to establish a general clause requiring onshore 
gas transmission pipeline operators to evaluate and mitigate risks to 
the public and environment as part of managing pipeline design, 
construction, operation, maintenance, and integrity, including 
management of change. The new paragraph would also invoke the 
requirements for management of change as outlined in ASME/ANSI B31.8S, 
section 11, and explicitly articulate the requirements for a management 
of change process that are applicable to onshore gas transmission 
pipelines.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that an important aspect of compliance with this 
requirement is to assure that records that demonstrate compliance with 
part 192 are complete and accurate. The proposed rule would add a new 
paragraph (e) that clearly articulates the requirements for records 
preparation and retention and requires that records be reliable, 
traceable, verifiable, and complete. Further, the proposed Appendix A 
would provide specific requirements for records retention for 
transmission pipelines.
    In addition, conforming amendments to paragraphs (a) and (b) list 
the effective date of the proposed requirements for newly regulated 
onshore gathering lines.
    Sec.  192.67 Records: Materials.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline material 
records are complete and accurate. The proposed rule would add a new 
Sec.  192.67 to require each operator of transmission pipelines to make 
and retain for the life of the pipeline the original steel pipe 
manufacturing records that document tests, inspections, and attributes 
required by the manufacturing specification in effect at the time the 
pipe was manufactured.
    Sec.  192.127 Records: Pipe design.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipe design records 
are complete and accurate. The proposed rule would add a new Sec.  
192.127 to require each operator of transmission pipelines to make and 
retain for the life of the pipeline records documenting pipe design to 
withstand anticipated external pressures and determination of design 
pressure for steel pipe.
    Sec.  192.150 Passage of internal inspection devices.
    The current pipeline safety regulations in 49 CFR 192.150 require 
that pipelines be designed and constructed to accommodate in-line 
inspection devices. Part 192 is silent on technical standards or 
guidelines for implementing requirements to assure pipelines are 
designed and constructed for ILI assessments. At the time these rules 
were promulgated, there was no consensus industry standard that 
addressed design and construction requirements for ILI. NACE Standard 
Practice, NACE SP0102-2010, ``In-line Inspection of Pipelines,'' has 
since been published and provides guidance in this area in Section 7. 
The incorporation of this standard into Sec.  192.150 will promote a 
higher level of safety by establishing consistent standards for the 
design and construction of line pipe to accommodate ILI devices.
    Sec.  192.205 Records: Pipeline components.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline component 
records are complete and

[[Page 20809]]

accurate. The proposed rule would add a new Sec.  192.205 to require 
each operator of transmission pipelines to make and retain records 
documenting manufacturing and testing information for valves and other 
pipeline components.
    Sec.  192.227 Qualification of welders.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline welding 
records are complete and accurate. The proposed rule would add a new 
paragraph Sec.  192.227(c) to require each operator of transmission 
pipelines to make and retain for the life of the pipeline records 
demonstrating each individual welder qualification in accordance with 
this section.
    Sec.  192.285 Plastic pipe: Qualifying persons to make joints.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline 
qualification records are complete and accurate. The proposed rule 
would add a new paragraph Sec.  192.285(e) to require each operator of 
transmission pipelines to make and retain for the life of the pipeline 
records demonstrating plastic pipe joining qualifications in accordance 
with this section.
    Sec.  192.319 Installation of pipe in a ditch.
    Section 192.319 prescribes requirements for installing pipe in a 
ditch, including requirements to protect pipe coating from damage 
during the process. However, during handling, lowering, and 
backfilling, sometimes pipe coating is damaged, which can compromise 
its ability to protect against external corrosion. An example of the 
consequences of such damage occurred in 2011 on the Bison Pipeline, 
operated by TransCanada Northern Border Pipeline, Inc. In this case, 
the probable cause of the incident was attributed to latent coating and 
mechanical damage caused during construction, which subsequently caused 
the pipeline to fail. To help prevent recurrence of such incidents, 
PHMSA has determined that additional requirements are needed to verify 
that pipeline coating systems for protection against external corrosion 
are not damaged during the installation and backfill process. 
Accordingly, this proposed rule would add a new paragraph (d) to 
require that onshore gas transmission operators perform an above-ground 
indirect assessment to identify locations of suspected damage promptly 
after backfill is completed and remediate any moderate or severe 
coating damage. Mechanical damage is also detectable by these indirect 
assessment methods, since the forces that are able to mechanically 
damage steel pipe usually result in detectable coating defects. 
Paragraph (d) does not apply to gas gathering lines or distribution 
mains. In addition, paragraph (d) would require each operator of 
transmission pipelines to make and retain for the life of the pipeline 
records documenting the coating assessment findings and repairs.
    Sec.  192.452 How does this subpart apply to converted pipelines 
and regulated onshore gathering lines?
    Section 192.452 prescribes corrosion control requirements for 
regulated onshore gathering lines. PHMSA proposes conforming amendments 
to the rule text in paragraph (b) to reflect other changes proposed in 
this NPRM for gas gathering lines.
    Sec.  192.461 External corrosion control: Protective coating.
    Section 192.461 prescribes requirements for protective coating 
systems. However, certain types of coating systems that have been used 
extensively in the pipeline industry can impede the process of cathodic 
protection if the coating disbonds from the pipe. The NTSB determined 
that this was a significant contributing factor in the major crude oil 
spill that occurred near Marshall, Michigan, in 2010. PHMSA has 
determined that additional requirements are needed to specify that 
coating should not impede cathodic protection and to ensure operators 
verify that pipeline coating systems for protection against external 
corrosion have not become compromised or damaged during the 
installation and backfill process. Accordingly, this proposed rule 
would amend paragraph (a)(4) to require that coating have sufficient 
strength to resist damage during installation and backfill, and add a 
new paragraph (f) to require that onshore gas transmission operators 
perform an above-ground indirect assessment to identify locations of 
suspected damage promptly after backfill is completed or anytime there 
is an indication that the coating might be compromised. It would also 
require prompt remediation of any moderate or severe coating damage.
    Sec.  192.465 External corrosion control: Monitoring.
    Section 192.465 currently prescribes that operators monitor 
cathodic protection and take prompt remedial action to correct 
deficiencies indicated by the monitoring. The provisions in Sec.  
192.465 do not specify the remedial actions required to correct 
deficiencies and do not define ``prompt.'' To address this potential 
issue, the proposed rule would amend paragraph (d) to require that 
remedial action must be completed promptly, but no later than the next 
monitoring interval specified in Sec.  192.465 or within one year, 
whichever is less. In addition, a new paragraph (f) is added to require 
onshore gas transmission operators to perform close-interval surveys if 
annual test station readings indicate cathodic protection is below the 
level of protection required in subpart I. Unless it is impractical to 
do so, close interval surveys must be completed with the protective 
current interrupted. Impracticality must be based on a technical 
reason, for example, a pipeline protected by direct buried sacrificial 
anodes (anodes directly connected to the pipeline), and not on cost 
impact. The proposed rule would also require each operator to take 
remedial action to correct any deficiencies indicated by the 
monitoring.
    Sec.  192.473 External corrosion control: Interference currents.
    Interference currents can negate the effectiveness of cathodic 
protection systems. Section 192.473 prescribes general requirements to 
minimize the detrimental effects of interference currents. However, 
specific requirements to monitor and mitigate detrimental interference 
currents have not been prescribed in subpart I. In 2003, PHMSA issued 
advisory bulletin ADB-03-06 (68 FR 64189). The bulletin advised each 
operator of a natural gas transmission or hazardous liquid pipeline to 
determine whether new steel pipelines are susceptible to detrimental 
effects from stray electrical currents. Based on this evaluation, an 
operator should carefully monitor and take action to mitigate 
detrimental effects. The operator should give special attention to a 
new pipeline's physical location, particularly where that location may 
subject the new pipeline to stray currents from other underground 
facilities, including other pipelines or induced currents from 
electrical transmission lines, whether aboveground or underground. 
Operators were strongly encouraged to review their corrosion control 
programs and to have qualified corrosion personnel present during 
construction to identify, mitigate, and monitor any detrimental stray 
currents that might damage new

[[Page 20810]]

pipelines. Since the advisory bulletin, PHMSA continues to identify 
cases where significant pipeline defects are attributed to corrosion 
caused by interference currents. Examples include CenterPoint Energy's 
CP line (2007), Keystone Pipeline (2012) and Overland Pass Pipeline 
(2012). Therefore, PHMSA has determined that additional requirements 
are needed to explicitly require that operators conduct interference 
surveys and to timely remediate adverse conditions. The proposed rule 
would add new paragraph (c) to require that onshore gas transmission 
operator programs include interference surveys to detect the presence 
of interference currents and to require taking remedial actions 
promptly after completion of the survey to adequately protect the 
pipeline segment from detrimental interference currents, but no later 
than 6 months in any case.
    Sec.  192.478 Internal corrosion control: Monitoring.
    Section 192.477 prescribes requirements to monitor internal 
corrosion if corrosive gas is being transported. However, the existing 
rules do not prescribe that operators continually or periodically 
monitor the gas stream for the introduction of corrosive constituents 
through system changes, changing gas supply, upset conditions, or other 
changes. This could result in pipelines that are not monitored for 
internal corrosion, because an initial assessment did not identify the 
presence of corrosive gas. In September 2000, following the Carlsbad 
explosion, PHMSA issued Advisory Bulletin 00-02, dated 9/1/2000 (65 FR 
53803). The bulletin advised owners and operators of natural gas 
transmission pipelines to review their internal corrosion monitoring 
programs and consider factors that influence the formation of internal 
corrosion, including gas quality and operating parameters. Pipeline 
operators continue to report incidents attributed to internal 
corrosion. Between 2002 and November 2012, 206 incidents have been 
reported that were attributed to internal corrosion. PHMSA has 
determined that additional requirements are needed to assure that 
operators effectively monitor gas stream quality to identify if and 
when corrosive gas is being transported and to mitigate deleterious gas 
stream constituents (e.g., contaminants or liquids). The proposed rule 
would add the new section 192.478 to require monitoring for deleterious 
gas stream constituents for onshore gas transmission operators, and 
require that gas monitoring data be evaluated quarterly. In addition, 
the proposed rule would add a requirement for onshore gas transmission 
operators to review the internal corrosion monitoring and mitigation 
program semi-annually and adjust the program as necessary to mitigate 
the presence of deleterious gas stream constituents. This is in 
addition to existing requirements to check coupons or other means to 
monitor for the actual presence of internal corrosion in the case of 
transporting a known corrosive gas stream.
    Sec.  192.485 Remedial measures: Transmission lines.
    Section 192.485 prescribes requirements for remedial measures to 
address general corrosion and localized corrosion pitting in 
transmission lines. For such conditions it specifies that the strength 
of pipe based on actual remaining wall thickness may be determined by 
the procedure in ASME/ANSI B31G or the procedure in AGA Pipeline 
Research Committee Project PR 3-805 (RSTRENG). PHMSA has determined 
that additional requirements are needed to assure such calculations 
have a sound basis. The proposed rule would revise section 192.485(c) 
to specify that pipe and material properties used in remaining strength 
calculations must be documented in reliable, traceable, verifiable, and 
complete records. If such records are not available, pipe and material 
properties used in the remaining strength calculations must be based on 
properties determined and documented in accordance with Sec.  192.607.
    Sec.  192.493 In-line inspection of pipelines.
    The current pipeline safety regulations in 49 CFR 192.921 and 
192.937 require that operators assess the material condition of 
pipelines in certain circumstances (e.g., IM assessments for pipelines 
that could affect high consequence areas) and allow use of in-line 
inspection tools for these assessments. Operators of gas transmission 
pipelines are required to follow the requirements of ASME/ANSI B31.8S, 
``Managing System Integrity of Gas Pipelines,'' in conducting their IM 
activities. ASME B31.8S provides limited guidance for conducting ILI 
assessments. Part 192 is silent on technical standards or guidelines 
for performing ILI assessments or implementing these requirements. At 
the time these rules were promulgated, there was no consensus industry 
standard that addressed ILI. Three related standards have since been 
published:
     API STD 1163-2005, ``In-Line Inspection Systems 
Qualification Standard.'' This Standard serves as an umbrella document 
to be used with and complement the NACE and ASNT standards below, which 
are incorporated by reference in API STD 1163.
     NACE Standard Practice, NACE SP0102-2010, ``In-line 
Inspection of Pipelines.''
     ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel 
Qualification and Certification.''
    The API standard is more comprehensive and rigorous than 
requirements currently incorporated into 49 CFR part 192. The 
incorporation of this standard into pipeline safety regulations will 
promote a higher level of safety by establishing consistent standards 
to qualify the equipment, people, processes and software utilized by 
the in-line inspection industry. The API standard addresses in detail 
each of the following aspects of ILI inspections, most of which are not 
currently addressed in the regulations:
     Systems qualification process
     Personnel qualification
     In-line inspection system selection
     Qualification of performance specifications
     System operational validation
     System Results qualification
     Reporting requirements
     Quality management system
    The incorporation of this standard into pipeline safety regulations 
will promote a higher level of safety by establishing consistent 
standards for conducting ILI assessments of line pipe. The NACE 
standard covers in detail each of the following aspects of ILI 
assessments, most of which are not currently addressed in part 192 or 
in ASME B31.8S:
     Tool selection
     Evaluation of pipeline compatibility with ILI
     Logistical guidelines, which includes survey acceptance 
criteria and reporting
     Scheduling
     New construction (planning for future ILI in new lines)
     Data analysis
     Data management
     The NACE standard provides a standardized questionnaire 
and specifies that the completed questionnaire should be provided to 
the ILI vendor. The questionnaire lists relevant parameters and 
characteristics of the pipeline section to be inspected.
    PHMSA believes that the consistency, accuracy and quality of 
pipeline in-line inspections would be improved by incorporating the 
consensus NACE standard into the regulations.
    The NACE standard applies to ``free swimming'' inspection tools 
that are carried down the pipeline by the

[[Page 20811]]

transported fluid. It does not apply to tethered or remotely controlled 
ILI tools, which can also be used in special circumstances (e.g., 
examination of laterals). While their use is less prevalent than free 
swimming tools, some pipeline IM assessments have been conducted using 
these tools. PHMSA considers that many of the provisions in the NACE 
standard can be applied to tethered or remotely controlled ILI tools. 
Therefore, PHMSA is proposing to allow the use of these tools, provided 
they generally comply with the applicable sections of the NACE 
standard.
    The ANSI/ASNT standard provides for qualification and certification 
requirements that are not addressed by 49 CFR part 192. The 
incorporation of this standard into pipeline safety regulations will 
promote a higher level of safety by establishing consistent standards 
to qualify the equipment, people, processes and software utilized by 
the in-line inspection industry. The ANSI/ASNT standard addresses in 
detail each of the following aspects, which are not currently addressed 
in the regulations:
     Requirements for written procedures
     Personnel qualification levels
     Education, training and experience requirements
     Training programs
     Examinations (testing of personnel)
     Personnel certification and recertification
     Personnel technical performance evaluations
    The proposed rule adds a new Sec.  192.493 to require compliance 
with the requirements and recommendations of the three consensus 
standards discussed above when conducting in-line inspection of 
pipelines.
    Sec.  192.503 General requirements.
    Section 192.503 prescribes the general test requirements for the 
operation of a new segment of pipeline, or returning to service a 
segment of pipeline that has been relocated or replaced. The proposed 
rule would add additional requirements to Sec.  192.503(a)(1) to 
reflect other requirements for determination of MAOP. These include 
Sec.  192.620 for alternative MAOP determination requirements and new 
Sec.  192.624 for verification of MAOP for onshore, steel, gas 
transmission pipeline segments that: (1) Has experienced a reportable 
in-service incident, as defined in Sec.  191.3, since its most recent 
successful subpart J pressure test, due to an original manufacturing-
related defect, a construction-, installation-, or fabrication-related 
defect, or a cracking-related defect, including, but not limited to, 
seam cracking, girth weld cracking, selective seam weld corrosion, hard 
spot, or stress corrosion cracking and the pipeline segment is located 
in one of the following locations: (i) A high consequence area as 
defined in Sec.  192.903; (ii) a class 3 or class 4 location; or (iii) 
a moderate consequence area as defined in Sec.  192.3 if the pipe 
segment can accommodate inspection by means of instrumented inline 
inspection tools (i.e., ``smart pigs''); (2) Pressure test records 
necessary to establish maximum allowable operating pressure per subpart 
J for the pipeline segment, including, but not limited to, records 
required by Sec.  192.517(a), are not reliable, traceable, verifiable, 
and complete and the pipeline segment is located in one of the 
following locations: (i) A high consequence area as defined in Sec.  
192.903; or (ii) a class 3 or class 4 location; or (3) the pipeline 
segment maximum allowable operating pressure was established in 
accordance with Sec.  192.619(c) of this subpart before [effective date 
of rule] and is located in one of the following areas: (i) A high 
consequence area as defined in Sec.  192.903; (ii) a class 3 or class 4 
location; or (iii) a moderate consequence area as defined in Sec.  
192.3 if the pipe segment can accommodate inspection by means of 
instrumented inline inspection tools (i.e., ``smart pigs'').
    Sec.  192.506 Transmission lines: Spike hydrostatic pressure test 
for existing steel pipe with integrity threats.
    The NTSB recommended repealing Sec.  192.619(c) and requiring that 
all gas transmission pipelines constructed before 1970 be subjected to 
a hydrostatic pressure test that incorporates a spike test 
(recommendation P-11-14). Currently, part 192 does not contain any 
requirement for operators to conduct spike hydrostatic pressure tests. 
In response to the NTSB recommendation, this NPRM proposes requirements 
for verification of MAOP in new Sec.  192.624, which requires that MAOP 
be established and documented for pipelines located in either an HCA or 
MCA meeting the conditions in Sec.  192.624(a)(1) through (3) using one 
or more of the methods in Sec.  192.624(c)(1) through (6). The pressure 
test method requires performance of a spike pressure test in accordance 
with new Sec.  192.506 if the pipeline includes legacy pipe or was 
constructed using legacy construction techniques or if the pipeline has 
experienced a reportable in-service incident, as defined in Sec.  
191.3, since its most recent successful subpart J pressure test, due to 
an original manufacturing-related defect, a construction-, 
installation-, or fabrication-related defect, or a crack or crack-like 
defect, including, but not limited to, seam cracking, girth weld 
cracking, selective seam weld corrosion, hard spot, or stress corrosion 
cracking.
    Sec.  192.517 Records.
    Section 192.517 prescribes the record requirements for each test 
performed under Sec. Sec.  192.505 and 192.507. The proposed rule would 
revise Sec.  192.517 to add the record requirements for Sec.  192.506.
    Sec.  192.605 Procedural manual for operations, maintenance, and 
emergencies.
    Section 192.605 prescribes requirements for the operator's 
procedural manual for operations, maintenance, and emergencies. Part 
192 contains numerous requirements intended to protect pipelines from 
overpressure events. These include mandatory pressure relieving or 
pressure limiting devices, inspections and tests of such devices, 
establishment of maximum allowable operating pressure, and 
administrative requirements to not operate the pipeline at pressures 
that exceed the MAOP, among others. Implicit in the requirements of 
Sec.  192.605 is the intent for operators to establish operational and 
maintenance controls and procedures to effectively implement these 
requirements and preclude operation at pressures that exceed MAOP. 
PHMSA expects that operator's procedures should already address this 
aspect of operations and maintenance, as it is a long-standing, 
critical aspect of safe pipeline operations. However, Sec.  192.605 
does not explicitly prescribe this aspect of the procedural controls. 
In addition, as a result of the San Bruno incident, Congress mandated 
in Section 23 of the Act that any exceedance of MAOP on a gas 
transmission pipeline be reported to PHMSA. As part of such reporting, 
the operator should inform PHMSA of the cause(s) of each exceedance. On 
December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which 
advised transmission operators of their responsibility under Section 23 
of the Act to report exceedances of MAOP that exceeds the margin 
(build-up) allowed for operation of pressure-limiting or control 
devices (i.e., report any pressure exceedances over the pressure 
limiting or control device set point as defined in applicable sections 
of Sec. Sec.  192.201(a)(2) or 192.739). Between December 21, 2012 and 
June 30, 2013, PHMSA received 14 such notifications. Therefore, PHMSA 
has determined that an additional requirement is needed to explicitly 
require procedures to maintain and operate pressure relieving devices 
and to control operating pressure to prevent

[[Page 20812]]

exceedance of MAOP. The proposed rule clarifies the existing 
requirements regarding such procedural controls.
    Sec.  192.607 Verification of pipeline material: Onshore steel 
transmission pipelines.
    Section 23 of the Act requires the Secretary of Transportation to 
require verification of records used to establish MAOP to ensure they 
accurately reflect the physical and operational characteristics of the 
pipelines and to confirm the established MAOP of the pipelines. PHMSA 
issued Advisory Bulletin 11-01 on January 10, 2011 (76 FR 1504) and 
Advisory Bulletin 12-06 on May 7, 2012 (77 FR 26822) to inform 
operators of this requirement. Operators have submitted information in 
their 2012 Annual Reports indicating that a portion of transmission 
pipeline segments do not have adequate records to establish MAOP or to 
accurately reflect the physical and operational characteristics of the 
pipeline. Therefore, PHMSA has determined that additional rules are 
needed to implement this requirement of the Act. Specifically, PHMSA 
has determined that additional rules are needed to require that 
operators conduct tests and other actions needed to understand the 
physical and operational characteristics for those segments where 
adequate records are not available, and to establish standards for 
performing these actions.
    This issue was addressed in detail at the Integrity Verification 
Process workshop on August 7, 2013. Major issues that were discussed 
include the scope of information needed and the methodology for 
verifying material properties. The most difficult information to 
obtain, from a technical perspective, is the strength of the steel. 
Conventional techniques would include cutting out a piece of pipe and 
destructively testing it to determine yield and ultimate tensile 
strength. PHMSA proposes to address this in the rule by allowing new 
non-destructive techniques if they can be validated to produce accurate 
results for the grade and type of pipe being evaluated. Such techniques 
have already been successfully validated for some grades of pipe.
    Another issue is the extremely high cost of excavating the pipeline 
in order to verify the material, and determining how much pipeline 
needs to be exposed and tested in order to have assurance of pipeline 
properties. PHMSA proposes to address this issue by specifying that 
operators take advantage of opportunities when the pipeline is exposed 
for other reasons, such as maintenance and repair, by requiring that 
material properties be verified whenever the pipe is exposed. Over 
time, pipeline operators will develop a substantial set of verified 
material data, which will provide assurance that material properties 
are reliably known for the entire population of inadequately documented 
segments. PHMSA proposes to require that operators continue this 
opportunistic material verification process until the operator has 
completed enough verifications to obtain high confidence that only a 
small percentage of inadequately documented pipe lengths have 
properties that are inconsistent with operators' past assumptions. The 
rule would specify the number of excavations required to achieve this 
level of confidence.
    Lastly, PHMSA proposes criteria that would require material 
verification for higher risk locations. Therefore, the proposed rule 
would add requirements for verification of pipeline material in new 
Sec.  192.607 for existing onshore, steel, gas transmission pipelines 
that are located in an HCA or a class 3 or class 4 location. PHMSA 
believes this approach appropriately addresses pipeline segment risk 
without extending the requirement to all pipelines where risk and 
potential consequences are not as significant, such as pipeline in 
remote rural areas.
    Requirements are also included to ensure that the results of this 
process are documented in records that are reliable, traceable, 
verifiable, and complete that must be retained for the life of the 
pipeline.
    Sec.  192.613 Continuing surveillance.
    Section 192.613 prescribes general requirements for continuing 
surveillance of the pipeline to determine and take action due to 
changes in the pipeline from, among other things, unusual operating and 
maintenance conditions. The 2011 hazardous liquid pipeline accident 
resulting in a crude oil spill into the Yellowstone River near Laurel, 
Montana was probably caused by scouring at a river crossing due to 
flooding. Based on recent examples of extreme weather events that did 
result, or could have resulted, in pipeline incidents, PHMSA has 
determined that additional requirements are needed to assure that 
operator procedures adequately address inspection of the pipeline and 
right-of-way for ``other factors affecting safety and operation'' 
following an extreme weather event such as a hurricane or flood, 
landslide, an earthquake, a natural disaster, or other similar event. 
The proposed rule would add a new paragraph (c) to require such 
inspections, specify the timeframe in which such inspections should 
commence, and specify the appropriate remedial actions must be taken to 
ensure safe pipeline operations. The new paragraph (c) would apply to 
both onshore transmission pipelines and their rights-of-way.
    Sec.  192.619 Maximum allowable operating pressure: Steel or 
plastic pipelines.
    The NTSB issued its report on the San Bruno incident that included 
a recommendation (P-11-15) that PHMSA amend its regulations so that 
manufacturing and construction-related defects can only be considered 
``stable'' if a gas pipeline has been subjected to a post-construction 
hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM 
proposes to revise the test pressure factors in Sec.  192.619(a)(2)(ii) 
to correspond to at least 1.25 MAOP for newly installed pipelines.
    In addition, Section 23 of the Act requires verification of records 
to confirm the established MAOP of the pipelines. Operators have 
submitted information in their 2012 Annual Reports indicating that a 
portion of gas transmission pipeline segments do not have adequate 
records to establish MAOP. For pipelines without an adequately 
documented basis for MAOP, the proposed rule adds a new paragraph (e) 
to Sec.  192.619 to require that certain onshore steel transmission 
pipelines that meet the criteria specified in Sec.  192.624(a), and 
that do not have adequate records to establish MAOP, must establish and 
document MAOP in accordance with new Sec.  192.624 using one or more of 
the methods in Sec.  192.624(c)(1) through (6), as discussed in more 
detail below.
    The proposed rule would also add a new paragraph (f) to explicitly 
require that records documenting tests, design, and other information 
necessary to establish MAOP be retained for the life of the pipeline.
    Lastly, the rule would incorporate conforming changes to Sec.  
192.619(a) to reflect changes to gas gathering regulations proposed in 
Sec. Sec.  192.8 and 192.9.
    Sec.  192.624 Maximum allowable operating pressure verification: 
Onshore steel transmission pipelines.
    Section 23 of the Act requires verification of records used to 
establish MAOP for pipe in class 3 and class 4 locations and high-
consequence areas in Class 1 and 2 locations to ensure they accurately 
reflect the physical and operational characteristics of the pipelines 
and to confirm the established MAOP of the pipelines. Operators have 
submitted information in their 2012 Annual Reports indicating that some 
gas transmission pipeline segments do not

[[Page 20813]]

have adequate records or testing to establish MAOP. For pipelines so 
identified, the Act requires that PHMSA promulgate regulations to 
require operators to test the segments to confirm the material strength 
of the pipe in HCAs that operate at stress levels greater than or equal 
to 30% SMYS. Such tests must be performed by pressure testing or other 
methods determined by the Secretary to be of equal or greater 
effectiveness.
    As a result of its investigation of the San Bruno accident, NTSB 
issued two related recommendations. NTSB recommended that PHMSA repeal 
Sec.  192.619(c) and require that all gas transmission pipelines 
constructed before 1970 be subjected to a hydrostatic pressure test 
that incorporates a spike test (P-11-14). NTSB also recommended that 
PHMSA amend the Federal pipeline safety regulations so that 
manufacturing- and construction-related defects can only be considered 
stable if a gas pipeline has been subjected to a post-construction 
hydrostatic pressure test of at least 1.25 times the maximum allowable 
operating pressure (P-11-15).
    The proposed rule would add a new Sec.  192.624 to address these 
mandates and recommendations. The rule would require that operators re-
establish and document MAOP for certain onshore steel transmission 
pipelines located in an HCA or MCA that meet one or more of the 
criteria specified in Sec.  192.624(a). Those criteria include: (1) Has 
experienced a reportable in-service incident, as defined in Sec.  
191.3, since its most recent successful subpart J pressure test, due to 
an original manufacturing-related defect, a construction-, 
installation-, or fabrication-related defect, or a cracking-related 
defect, including, but not limited to, seam cracking, girth weld 
cracking, selective seam weld corrosion, hard spot, or stress corrosion 
cracking and the pipeline segment is located in one of the following 
locations: (i) A high consequence area as defined in Sec.  192.903; 
(ii) a class 3 or class 4 location; or (iii) a moderate consequence 
area as defined in Sec.  192.3 if the pipe segment can accommodate 
inspection by means of instrumented inline inspection tools (i.e., 
``smart pigs''); (2) Pressure test records necessary to establish 
maximum allowable operating pressure per subpart J for the pipeline 
segment, including, but not limited to, records required by Sec.  
192.517(a), are not reliable, traceable, verifiable, and complete and 
the pipeline segment is located in one of the following locations: (i) 
A high consequence area as defined in Sec.  192.903; or (ii) a class 3 
or class 4 location; or (3) the pipeline segment maximum allowable 
operating pressure was established in accordance with Sec.  192.619(c) 
of this subpart before [effective date of rule] and is located in one 
of the following areas: (i) A high consequence area as defined in Sec.  
192.903; (ii) a class 3 or class 4 location; or (iii) a moderate 
consequence area as defined in Sec.  192.3 if the pipe segment can 
accommodate inspection by means of instrumented inline inspection tools 
(i.e., ``smart pigs'').
    The methods specified in Sec.  192.624 include the pressure test 
method. If the pipeline includes legacy pipe or was constructed using 
legacy construction techniques or the pipeline has experienced a 
reportable in-service incident, as defined in Sec.  191.3, since its 
most recent successful subpart J pressure test, due to an original 
manufacturing-related defect, a construction-, installation-, or 
fabrication-related defect, or a crack or crack-like defect, a spike 
pressure test in accordance with new Sec.  192.506 would be required. 
For modern pipe without the aforementioned risk factors, a pressure 
test in accordance with Sec.  192.505 would be allowed.
    Other methods to reestablish MAOP for pipe currently operating 
under Sec.  192.619(c) would also be allowed. PHMSA has determined that 
the following methods would provide equal or greater effectiveness as a 
pressure test:
    (i) De-rating the pipe segment such that the new MAOP is less than 
historical actual sustained operating pressure by using a safety factor 
of 0.80 times the sustained operating pressure (equivalent to a 
pressure test using gas or water as the test medium with a test 
pressure of 1.25 times MAOP). For segments that operate at stress 
levels of less than 30% SMYS a safety factor of 0.90 times sustained 
operating pressure is allowed (equivalent to a pressure test of 1.11 
times MAOP), supplemented with additional integrity assessments, and 
preventive and mitigative measures specified in the proposed rule.
    (ii) Replacement of the pipe, which would require a new pressure 
test that conforms with subpart J before being placed in service,
    (iii) An in-line inspection and Engineering Critical Assessment 
process using technical criteria to establish a safety margin 
equivalent to that provided by a pressure test, or
    (iv) Use of other technology that the operator demonstrates 
provides an equivalent or greater level of safety, provided PHMSA is 
notified in advance.
    The proposed rule establishes requirements for pipelines operating 
at stress levels of less than 30% of SMYS based on technical 
information provided in Interstate Natural Gas Association of America/
American Gas Association Final Report No. 13-180, ``Leak vs. Rupture 
Thresholds for Material and Construction Anomalies,'' December 2013. 
The report references a 2010 study by Kiefner & Associates, Inc. 
``Numerical Modeling and Validation for Determination of the Leak/
Rupture Boundary for Low-Stress Pipelines'' performed under contract to 
the Gas Technology Institute (GTI). The Kiefner/GTI report evaluated 
theoretical fracture models and supporting test data in order to define 
a possible leak-rupture threshold stress level. The report pointed out 
that ``no evidence was found that a propagating ductile rupture could 
arise from an incident attributable to any one of these causes in a 
pipeline that is being operated at a hoop stress level of 30% of SMYS 
or less.'' In addition, the INGAA/AGA report included a review of 
Kiefner & Associates, Inc. failure investigation reports, which 
concluded that all manufacturing related defects failing under the 
action of hoop stress alone failed as leaks if the hoop stress level 
was 30% SMYS or less except for one case out of 94 which failed at 27% 
of SMYS. The INGAA/AGA report states that a hydrostatic test to 1.25 
times the MAOP is unnecessary to reasonably assure stability of pipe 
manufacturing construction related features in pipe meeting the 
following conditions: (1) Ductile fracture initiation is assured by 
showing that the pipe has an operating temperature above the brittle 
fracture initiation temperature; (2) interaction with in-service 
degradation mechanics such as selective seam weld corrosion or previous 
mechanical damage is absent; (3) hoop stress is 30% or less; (4) mill 
pressure testing was conducted at 60% SMYS or more, established by 
documented conformance to applicable pipe product specifications (e.g., 
API 5L) or company specifications; and (5) pipe is 6 NPS or smaller. 
For pipes that are 8 NPS or larger but still meeting the conditions 
mentioned above, hydrostatic pressure testing to 1.25 times the MAOP is 
still prudent, since theoretical analysis as well as full scale 
laboratory tests show that failure as a rupture is possible for stress 
thresholds below 30% of SMYS. However, NPS 8 pipe may be prioritized 
lower than larger pipe because there were no reported incidents of 
service rupture in pipe that size where all other criteria were met. 
PHMSA plans to limit stress levels, pressures, and pipe diameters that 
can meet the potential impact

[[Page 20814]]

radius and require alternative integrity and preventative and 
mitigative measures for pipelines that use these criteria to establish 
MAOP.
    The above approach implements the regulatory mandate in the Act for 
segments in HCAs. In addition, the scope includes additional pipe 
segments in the newly defined moderate consequence areas. This approach 
is intended to address the NTSB recommendations and to provide 
increased safety in areas where a pipeline rupture would have a 
significant impact on the public or the environment. PHMSA does not 
propose to repeal 49 CFR 192.619(c) for segments located outside of 
HCAs or MCAs where the routine presence of persons is not expected.
    The Engineering Critical Assessment process requires the 
conservative analysis of: Any in-service cracks, crack-like defects 
remaining in the pipe, or the largest possible crack that could remain 
in the pipe, including crack dimensions (length and depth) to determine 
the predicted failure pressure (PFP) of each defect; failure mode 
(ductile, brittle, or both) for the microstructure, location, type of 
defect, and operating conditions (which includes pressure cycling); and 
failure stress and crack growth analysis to determine the remaining 
life of the pipeline. An Engineering Critical Assessment must use 
techniques and procedures developed and confirmed through research 
findings provided by PHMSA, and other reputable technical sources for 
longitudinal seam and crack growth such as PHMSA's 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 on the internet at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
    Section 23 requires pipeline operators to conduct a records 
verification for pipelines located in certain areas to ensure that the 
records accurately reflect the physical and operational characteristics 
of the pipelines and confirm the established MAOP. Congress further 
directed DOT to require the owner or operator to reconfirm a maximum 
allowable operating pressure for pipelines with insufficient records. 
This rule proposes methods for satisfying this direction from Congress. 
In analyzing the impact of the proposed methods, PHMSA determined that 
they would result in large cost savings ($2.67 billion over 15 years 
discounted at 7%, $3.67 billion discounted at 3%) relative to current 
regulatory requirements for pipelines with insufficient records in 49 
CFR 192.107(b), The results of that action indicated that problems 
similar to those that contributed to the San Bruno incidents are more 
widespread than previously believed. As a result, the proposed rule 
would establish consistent standards by which operators would correct 
these issues in a way that is more cost effective than the current 
regulations would require (which could require more extensive 
destructive testing, pressure testing, and/or pipe replacement). PHMSA 
did not identify any significant adverse safety impacts from allowing 
operators to use the proposed methods instead of those in the current 
regulations. See section 4.1.2.3 in the regulatory impact analysis for 
the analysis of the cost savings.
    PHMSA estimated the cost savings to operators associated with the 
Section 23(c) mileage. Existing regulatory requirements [Sec.  
192.107(b)] related to bad or missing records would be more costly for 
operators to achieve compliance. Under existing regulations, in order 
for pipelines with insufficient records to maintain operating pressure, 
operators must excavate the pipeline at every 10 lengths of pipe 
(commonly referred to as joints) in accordance with section II-D of 
appendix B of part 192 (as specified in Sec.  192.107(b)), do a cutout, 
determine material properties by destructive tensile test, and repair 
the pipe. The process is similar to doing a repair via pipe 
replacement. PHMSA developed a blended average for performing such a 
cutout material verification ($75,000) by reviewing typical costs to 
repair a small segment of pipe by pipe replacement. The blended average 
accounted for various pipe diameters and regional cost variance. PHMSA 
assumed each joint is 40 feet long; ten joints is 400 ft. The number of 
cutouts required by existing rules is therefore the miles subject to 
this requirement multiplied by 5,280/400.
    The proposed rule would allow operators to perform a sampling 
program that opportunistically takes advantage of repairs and 
replacement projects to verify material properties at the same time. 
Over time, operators will collect enough information gain significant 
confidence in the material properties of pipe subject to this 
requirement. The proposed rule nominally targets conducting an average 
of one material documentation process per mile. In addition, operators 
would be allowed to perform nondestructive examinations, in lieu of 
cutouts and destructive testing, when the technology provides a 
demonstrable level of confidence in the result. PHMSA estimated that 
the incremental unit cost of adding material documentation activities 
to a repair or replacement activity would be approximately $17,000 per 
instance.
    The proposed methods for addressing pipelines with insufficient 
records are exclusively applicable to HCA and all Class 3 and 4 
locations. Therefore, if the proposed rule were in effect, operators 
would be able to use the new methods for addressing pipeline with 
insufficient records in HCA and all Class 3 and 4 locations, but they 
would be required to comply with existing (more expensive) requirements 
for addressing the same issue for pipelines located outside HCA and all 
Class 3 and 4 locations. Locations outside HCAs and all Class 3 and 4 
are by definition lower risk, meaning if incidents occur, the 
consequences are expected to be smaller than HCA and all Class 3 and 4 
locations. PHMSA is considering including provisions in the final rule 
that would enable operators to use the proposed methods for addressing 
pipelines with insufficient records in locations outside HCAs and all 
Class 3 and 4. To maintain flexibility, the proposed methods may be an 
option to existing requirements--as opposed to a replacement of those 
requirements. PHMSA requests comments on the impacts of allowing 
operators to use the new methods for addressing insufficient records 
beyond HCAs and all Class 3 and 4 locations. What safety risks, if any, 
should PHMSA consider? What are the potential cost savings?
    Sec.  192.710 Pipeline assessments.
    Currently, part 192 does not contain any requirement for operators 
to conduct integrity assessments of onshore transmission pipelines that 
are not HCA segments as defined in Sec.  192.903 and therefore not 
subject to subpart O; i.e., pipelines that are not located in a high 
consequence area (HCA). Currently, only approximately 7% of onshore gas 
transmission pipelines are located in HCAs. However, coincident with 
integrity assessments of HCA segments, industry has, as a practical 
matter, assessed substantial amounts of pipeline in non-HCA

[[Page 20815]]

segments. For example, INGAA noted (see Topic A comments, above) that 
approximately 90 percent of Class 3 and 4 mileage not in HCAs are 
presently assessed through over-testing during IM assessments. This is 
due, in large part, because ILI or pressure testing, by their nature, 
assess large continuous segments that may contain some HCA segments but 
that could also contain significant amounts of non- HCA segments. In 
addition, based on the integrity management principle of continuous 
improvement, INGAA members have committed (via its IMCI action plan 
discussed under Topic A, above) to first extend some degree of 
integrity management to approximately 90 percent of people who live, 
work or otherwise congregate near pipelines (that is, within the 
pipelines' Potential Impact Radius, or PIR) by 2012. By 2020, INGAA 
operators have committed to perform full integrity management on 
pipelines covering 90 percent of the PIR population. At a minimum, all 
ASME/ANSI B31.8S requirements will be applied, including mitigating 
corrosion anomalies and applying integrity management principles. 
Continuing to areas of less population density, INGAA members plan to 
apply integrity management principles to pipelines covering 100 percent 
of the PIR population by 2030.
    Given this level of commitment, PHMSA has determined that it is 
appropriate to codify requirements that additional gas transmission 
pipelines have an integrity assessment on a periodic basis to monitor 
for, detect, and remediate deleterious pipeline defects and injurious 
anomalies. However, INGAA does not represent all pipeline operators 
subject to part 192. In addition, in order to achieve the desired 
outcome of performing assessments in areas where people live, work, or 
congregate, while minimizing the cost of identifying such locations, 
PHMSA proposes to base the requirements for identifying those locations 
on processes already being implemented by pipeline operators.
    The proposed rule would add a new Sec.  192.710 to require that 
pipeline segments in moderate consequence areas that can accommodate 
inspection by means of instrumented inline inspection tools (i.e., 
``smart pigs'') be assessed within 15 years and every 20 years 
thereafter. PHMSA proposes to define a new term ``moderate consequence 
area'' or MCA. The definition is based on the same methodology as 
``high consequence areas'' as specified in Sec.  192.903, but with less 
stringent criteria. Moderate consequence areas will be used to define 
the subset of locations where integrity assessments are required. This 
approach is proposed as a means to minimize the effort needed on the 
part of operators to identify the MCAs, since transmission operators 
must have already performed the analysis in order to have identified 
the HCAs, or verify that they have no HCAs. In addition, the MCA 
definition would include locations where interstate highways, freeways, 
and expressways, and other principal 4-lane arterial roadways are 
located within the PIR.
    Because significant non-HCA pipeline mileage has been previously 
assessed in conjunction with an assessment of HCA segments in the same 
pipeline, PHMSA also proposes to allow the use of those prior 
assessments for non-HCA segments to comply with the new Sec.  192.710, 
provided that the assessment was conducted in conjunction with an 
integrity assessment required by subpart O.
    The proposed rule would also require that the assessment required 
by new Sec.  192.710 be conducted using the same methods as proposed 
for HCAs (see Sec.  192.921, below).
    Sec.  192.711 Transmission lines: General requirements for repair 
procedures.
    Section 192.711 prescribes general requirements for repair 
procedures. For non-HCA segments, the existing rule requires that 
permanent repairs be made as soon as feasible. However, no specific 
repair criteria are provided and no specific timeframe or pressure 
reduction requirements are provided. PHMSA has determined that more 
specific repair criteria are needed for pipelines not covered under the 
integrity management rule. The proposed rule would amend paragraph 
(b)(1) of section 192.711 to require that specific conditions (i.e., 
repair criteria) defined in proposed Sec.  192.713 (see below) be 
remediated, and to require a reduction of operating pressure for 
conditions that present an immediate hazard.
    Sec.  192.713 Transmission lines: Permanent field repair of 
imperfections and damages.
    Section 192.713 prescribes requirements for the permanent repair of 
pipeline imperfection or damage that impairs the serviceability of pipe 
in a steel transmission line operating at or above 40 percent of SMYS. 
PHMSA has determined that more explicit requirements are needed to 
better identify criteria for the severity of imperfection or damage 
that must be repaired, and to identify the timeframe within which 
repairs must be made. Further, PHMSA has determined that such repair 
criteria should apply to any transmission pipeline not covered under 
subpart O, Integrity Management regulations. PHMSA believes that 
establishing these non-HCA segment repair conditions are important 
because, even though they are not within the defined high consequence 
locations, they could be located in populated areas and are not without 
consequence. For example, as reported by operators in the 2011 annual 
reports, while there are approximately 20,000 miles of gas transmission 
pipe in HCA segments, there are approximately 65,000 miles of pipe in 
Class 2, 3, and 4 populated areas. PHMSA believes it is prudent and 
appropriate to include criteria to assure the timely repair of 
injurious pipeline defects in non-HCA segments. These changes will 
ensure the prompt remediation of anomalous conditions, while allowing 
operators to allocate their resources to high consequence areas on a 
higher priority basis. The proposed rule would amend Sec.  192.713 to 
establish immediate, two-year, and monitored conditions which the 
operator must remediate or monitor to assure pipeline safety. PHMSA 
proposes to use the same criteria as proposed for HCAs (see 192.933, 
below), except that conditions for which a one-year response is 
required in HCAs would require a two-year response in non-HCA segments. 
In addition, PHMSA proposes to prescribe more explicit requirements for 
in situ evaluation of cracks and crack-like defects using in-the-ditch 
tools whenever required, such as when an ILI, SCCDA, pressure test 
failure, or other assessment identifies anomalies that suggest the 
presence of such defects.
    Sec.  192.750 Launcher and receiver safety.
    PHMSA has determined that more explicit requirements are needed for 
safety when performing maintenance activities that utilize launchers 
and receivers to insert and remove maintenance tools and devices. Such 
facilities are subjected to pipeline system pressures. Current 
regulations for hazardous liquid pipelines (part 195) have, since 1981, 
contained such safety requirements for scraper and sphere facilities 
(re: Sec.  195.426). However, current regulations for gas pipelines 
(part 192) do not similarly require controls or instrumentation to 
protect against inadvertent breach of system integrity due to incorrect 
operation of launchers and receivers for in-line inspection tools, 
scraper, and sphere facilities. Accordingly, the proposed rule would 
add a new section Sec.  192.750 to require a suitable means to relieve 
pressure in the barrel and either a means to indicate the pressure in 
the

[[Page 20816]]

barrel or a means to prevent opening if pressure has not been relieved.
    Sec.  192.911 What are the elements of an integrity management 
program?
    Paragraph (k) of Sec.  192.911 requires that integrity management 
programs include a management of change process as outlined in ASME/
ANSI B31.8S, section 11. PHMSA has determined that specific attributes 
and features of the management of change process as currently specified 
in ASME/ANSI B31.8S, section 11, should be codified directly within the 
text of Sec.  192.911(k). The proposed rule would amend paragraph (k) 
to specify that the features of the operator's management of change 
process must include the reason for change, authority for approving 
changes, analysis of implications, acquisition of required work 
permits, documentation, communication of change to affected parties, 
time limitations, and qualification of staff. These general attributes 
of change management are already required by virtue of being invoked by 
reference to ASME/ANSI B31.8S. However, PHMSA believes it will improve 
the visibility and emphasis on these important program elements to 
require them directly in the rule text.
    Sec.  192.917 How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?
    Section 192.917 requires that integrity management programs for 
covered pipeline segments identify potential threats to pipeline 
integrity and use the threat identification in its integrity program. 
Included within this performance-based process are requirements to 
identify threats to which the pipeline is susceptible, collect data for 
analysis, and perform a risk assessment. Special requirements are 
included to address plastic pipe and particular threats such as third 
party damage and manufacturing and construction defects. Following the 
San Bruno accident, the NTSB recommended that Pacific Gas and Electric 
(PG&E) assess every aspect of its integrity management program, paying 
particular attention to the areas identified in the investigation, and 
implement a revised program that includes, at a minimum,
    (1) a revised risk model to reflect the Pacific Gas and Electric 
Company's actual recent experience data on leaks, failures, and 
incidents;
    (2) consideration of all defect and leak data for the life of each 
pipeline, including its construction, in risk analysis for similar or 
related segments to ensure that all applicable threats are adequately 
addressed;
    (3) a revised risk analysis methodology to ensure that assessment 
methods are selected for each pipeline segment that address all 
applicable integrity threats, with particular emphasis on design/
material and construction threats; and
    (4) an improved self-assessment that adequately measures whether 
the program is effectively assessing and evaluating the integrity of 
each covered pipeline segment (NTSB recommendation P-11-29).
    In addition, the NTSB recommended that PG&E conduct threat 
assessments using the revised risk analysis methodology incorporated in 
its integrity management program, as recommended in Safety 
Recommendation P-11-29, and report the results of those assessments to 
the California Public Utilities Commission and the Pipeline and 
Hazardous Materials Safety Administration (NTSB recommendation P-11-
30). PHMSA has also analyzed the issues the NTSB identified in the 
investigation related to information analysis and risk assessment. 
PHMSA held a workshop on July 21, 2011 to address perceived 
shortcomings in the implementation of integrity management risk 
assessment processes and the information and data analysis (including 
records) upon which such risk assessments are based. PHMSA sought input 
from stakeholders on these issues and has determined that additional 
clarification and specificity is needed for existing performance-based 
rules. These clarifications define and emphasize the specific functions 
that are required for risk assessment and effective risk management.
    These aspects of integrity management have been an integral part of 
PHMSA's expectations for integrity management since the inception of 
the program. As specified in Sec.  192.907(a), PHMSA expected operators 
to start with a framework, which would evolve into a more detailed and 
comprehensive program, and that the operator must continually improve 
its integrity management program, as it learned more about the process 
and about the material condition of its pipelines through integrity 
assessments.
    PHMSA elaborated on this philosophy in the notice of final 
rulemaking for subpart O (68 FR 69778):

    The intent of allowing a framework was to acknowledge that an 
operator cannot develop a complete, fully mature integrity 
management plan in a year. Nevertheless, it is important that an 
operator have thought through how the various elements of its plan 
relate to each other early in the development of its plan. The 
framework serves this purpose. . . . It need not be fully developed 
or at the level of detail expected of final integrity management 
plans. The framework is an initial document that evolves into a more 
detailed and comprehensive program.

    The clarifications and additional specificity proposed in this NPRM 
(with respect to processes for implementing the threat identification, 
risk assessment, and preventive and mitigative measures program 
elements), reflect PHMSA's expectation regarding the degree of progress 
operators should be making, or should have made, during the first 10 
years of the integrity management program.
    The current integrity management rule invokes ASME/ANSI B31.8S by 
reference to require that operators implement specific attributes and 
features of the threat identification, data analysis, and risk 
assessment process. PHMSA has determined that those specific attributes 
and features of the threat identification, data analysis, and risk 
assessment processes as currently specified in ASME/ANSI B31.8S, 
section 11, should be codified within the text of Sec.  192.917. While 
continuing to incorporate the industry standard by reference, the 
proposed rule would amend Sec.  192.917 to insert certain critical 
features of the industry standard (ASME/ANSI B31.8S) directly into the 
body of the Federal regulation. Specifically, PHMSA proposes to specify 
several pipeline attributes that must be included in pipeline risk 
assessments and to explicitly require that operators integrate analyzed 
information, and ensure that data be verified and validated to the 
maximum extent practical. PHMSA also acknowledges that objective, 
documented data is not always available or obtainable. To the degree 
that subjective data from subject matter experts must be used, PHMSA 
proposes to require that an operator's program include specific 
features to compensate for subject matter expert bias.
    In addition, PHMSA proposes to clarify the performance-based risk 
assessment aspects of the IM rule to specify that operators perform 
risk assessments that are adequate to evaluate the effects of 
interacting threats; determine additional preventive and mitigative 
measures needed, analyze how a potential failure could affect high 
consequence areas, including the consequences of the entire worst-case 
incident scenario from initial failure to incident termination; 
identify the contribution to risk of each risk factor, or each unique 
combination of risk factors that interact or simultaneously contribute 
to risk at a common location, account for, and compensate for, 
uncertainties in the

[[Page 20817]]

model and the data used in the risk assessment; and evaluate risk 
reduction associated with candidate risk reduction activities such as 
preventive and mitigative measures. In addition, in response to 
specific NTSB recommendation P-11-18, PHMSA proposes performance-based 
language to require that operators validate their risk models in light 
of incident, leak, and failure history and other historical 
information. Such features are currently requirements by virtue of 
being invoked by reference in ASME/ANSI B31.8S. However, PHMSA believes 
that these important aspects of integrity management will receive 
greater emphasis and awareness if incorporated directly into the rule 
text. The proposed rule would also amend the requirements for plastic 
pipe to provide specific examples of integrity threats for plastic pipe 
that must be addressed.
    Lastly, PHMSA proposes to revise the criteria in Sec.  
192.917(e)(3) and (4) for addressing the threat of manufacturing and 
construction defects and concluding that latent defects are stable as 
recommended in NTSB recommendation P-11-15.
    Sec.  192.921 How is the baseline assessment to be conducted?
    Section 192.921 requires that pipelines subject to integrity 
management rules have an integrity assessment. Current rules allow the 
use of in-line inspection, pressure testing in accordance with subpart 
J, direct assessment for the threats of external corrosion, internal 
corrosion, and stress corrosion cracking, and other technology that the 
operator demonstrates provides an equivalent level of understanding of 
the condition of the pipeline. Following the San Bruno accident, PHMSA 
has determined that baseline assessment methods should be clarified to 
emphasize in-line inspection and pressure testing over direct 
assessment. At San Bruno, PG&E relied heavily on direct assessment 
under circumstances for which direct assessment was not effective. 
Further, ongoing research and industry response to the ANPRM is 
beginning to indicate that stress corrosion cracking direct assessment 
is not as effective, and does not provide an equivalent understanding 
of pipe conditions with respect to SCC defects, as ILI or hydrostatic 
pressure testing at test pressures that exceed those test pressures 
required by subpart J (i.e., ``spike'' hydrostatic pressure test). 
Therefore, the proposed rule would require that direct assessment only 
be allowed when the pipeline cannot be assessed using in-line 
inspection tools. The proposed rule would also add three additional 
assessment methods: (1) A ``spike'' hydrostatic pressure test, which is 
particularly well suited to address SCC and other cracking or crack-
like defects, (2) guided wave ultrasonic testing (GWUT) which is 
particularly appropriate in cases where short segments, such as road or 
railroad crossing, are difficult to assess, and (3) excavation with 
direct in situ examination.
    The current rule merely indicates that in-line inspection (ILI) is 
an accepted assessment method. The regulations are currently silent on 
a number of issues that significantly impact the quality and 
effectiveness of ILI assessment results. Such considerations are 
described in ASME/ANSI B31.8S, but limited guidance is provided. As 
discussed above, the proposed rule strengthens guidance in this area by 
adding a new Sec.  192.493 to require compliance with the requirements 
and recommendations of API STD 1163-2005, NACE SP0102-2010, and ANSI/
ASNT ILI-PQ-2010 when conducting in-line inspection of pipelines. 
Section 192.921(a)(1) would be revised to require compliance with Sec.  
192.493 instead of ASME B31.8S for baseline ILI assessments for covered 
segments. In addition, a person qualified by knowledge, training, and 
experience would be required to analyze the data obtained from an 
internal inspection tool to determine if a condition could adversely 
affect the safe operation of the pipeline, and must explicitly consider 
uncertainties in reported results (including, but not limited to, tool 
tolerance, detection threshold, probability of detection, probability 
of identification, sizing accuracy, conservative anomaly interaction 
criteria, location accuracy, anomaly findings, and unity chart plots or 
equivalent for determining uncertainties and verifying actual tool 
performance) in identifying and characterizing anomalies.
    GWUT has been in use by pipeline operators for several years. 
Previously, operators were required by Sec.  192.921(a)(4) to submit a 
notification to PHMSA as an ``other technology'' assessment method, in 
order to use GWUT. In 2007, PHMSA developed guidelines for how it would 
evaluate notifications for use of GWUT. These guidelines have been 
effectively used for seven years, and PHMSA has gained confidence that 
GWUT can be effectively used to assess the integrity of short segments 
of pipe. PHMSA proposes to incorporate these guidelines into a new 
Appendix F, which would be invoked in Sec.  192.921. Therefore, 
notification for use of GWUT would no longer be required.
    ASME B31.8S, Section 6.1, describes both excavation and direct in 
situ examination as specialized integrity assessment methods, 
applicable to particular circumstances:

    It is important to note that some of the integrity assessment 
methods discussed in para. 6 only provide indications of defects. 
Examination using visual inspection and a variety of nondestructive 
examination (NDE) techniques are required, followed by evaluation of 
these inspection results in order to characterize the defect. The 
operator may choose to go directly to examination and evaluation for 
the entire length of the pipeline segment being assessed, in lieu of 
conducting inspections. For example, the operator may wish to 
conduct visual examination of aboveground piping for the external 
corrosion threat. Since the pipe is accessible for this technique 
and external corrosion can be readily evaluated, performing in-line 
inspection is not necessary.

    PHMSA proposes to clarify its requirements to explicitly add 
excavation and direct in situ examination as acceptable assessment 
methods.
    PHMSA also proposes that mandatory integrity assessments proposed 
for non-HCA segments (see Sec.  192.710, above) could also use these 
assessment methods.
    Sec.  192.923 How is direct assessment used and for what threats?
    As discussed in the changes to Sec. Sec.  192.927 and 192.929 
below, the proposed rule would incorporate by reference NACE SP0206-
2006, ``Internal Corrosion Direct Assessment Methodology for Pipelines 
Carrying Normally Dry Natural Gas,'' for addressing ICDA and NACE 
SP0204-2008, ``Stress Corrosion Cracking Direct Assessment,'' for 
addressing SCCDA. Sections 192.923(b)(2) and (b)(3) would be revised to 
require compliance with these standards.
    Sec.  192.927 What are the requirements for using Internal 
Corrosion Direct Assessment (ICDA)?
    Internal corrosion (IC) is a degradation mechanism in which steel 
pipe loses wall thickness due to corrosion initiating on the inside 
surface of the pipe. IC is one of several threats that can impact 
pipeline integrity. IM regulations in 49 CFR part 192 require that 
pipeline operators assess covered pipe segments periodically to detect 
degradation from threats that their analyses have indicated could 
affect the segment. Not all covered segments are subject to an IC 
threat, but some are. IC direct assessment (ICDA) is an assessment 
technique that can be used to address this threat for gas pipelines. 
ICDA involves evaluation and analysis to determine locations at which a

[[Page 20818]]

corrosive environment is likely to exist inside a pipeline followed by 
excavation and direct examination of the pipe wall to determine whether 
IC is occurring.
    Section 192.927 specifies requirements for gas transmission 
pipeline operators who use ICDA for IM assessments. The requirements in 
Sec.  192.927 were promulgated before the NACE standard was published. 
They require that operators follow ASME/ANSI B31.8S provisions related 
to ICDA. PHMSA has reviewed the NACE standard and finds that it is more 
comprehensive and rigorous than either Sec.  192.927 or ASME B31.8S in 
many respects. Some of the most important features in the NACE standard 
are:
     The NACE standard requires more direct examinations in 
most cases.
     The NACE standard encompasses the entire pipeline segment 
and requires that all inputs and outputs be evaluated.
     The NACE standard indirect inspection model is different 
than the Gas Technology Institute (GTI) model currently referenced in 
Sec.  192.927, but is considered to be equivalent or superior. Its 
range of applicability with respect to operating pressure is greater 
than the GTI model, thus allowing use of ICDA in pipelines with lower 
operating pressures and higher flow velocities.
     The NACE standard provides additional guidance on how to 
effectively determine areas to excavate for detailed examinations for 
internal corrosion.
    The existing requirements in Sec.  192.927 have one particular 
aspect that has proven problematic. The definition of regions and 
requirements for selection of direct examination locations in the 
regulations are tied to the covered segment. Covered segment boundaries 
are determined by population density and other consequence factors 
without regard to the orientation of the pipe and the presence of 
locations at which corrosive agents may be introduced or may collect 
and where internal corrosion would most likely be detected (e.g., low 
spots). Section 192.927 requires that locations selected for excavation 
and detailed examination be within covered segments, meaning that the 
locations at which IC would most likely be detected may not be 
examined. Thus, the existing requirements do not always facilitate the 
discovery of internal corrosion that could affect covered segments. 
PHMSA is proposing to address this problem by incorporating NACE 
SP0206-2006 and by establishing additional requirements for addressing 
covered segments within the technical process defined by NACE SP0206-
2006.
    This proposed rule would require that operators perform two direct 
examinations within each covered segment the first time ICDA is 
performed. These examinations are in addition to those required to 
comply with the NACE standard practice. The additional examinations are 
consistent with the current requirement in Sec.  192.927(c)(5)(ii) that 
operators apply more restrictive criteria when conducting ICDA for the 
first time and are intended to provide a verification, within the HCA, 
that the results of applying the NACE process for the ICDA are 
acceptable. Applying the NACE process requires a more precise knowledge 
of the pipeline's orientation (particularly slope) than operators may 
have in many cases. Conducting examinations within the HCA during the 
first application of ICDA will verify that application of the ICDA 
process provides adequate information about the covered segment. 
Operators who identify IC on these additional examinations, even though 
excavations at locations determined using the NACE process did not 
identify any, will know that improvements to their knowledge of 
pipeline orientation or other adjustments to their application of the 
NACE process to the covered segment will be needed for future uses of 
ICDA. Sec.  192.927(b) and (c) are revised to address these issues.
    Sec.  192.929 What are the requirements for using Direct Assessment 
for Stress Corrosion Cracking (SCCDA)?
    Stress corrosion cracking (SCC) is a degradation mechanism in which 
steel pipe develops tight cracks through the combined action of 
corrosion and tensile stress (residual or applied). These cracks can 
grow or coalesce to affect the integrity of the pipeline. SCC is one of 
several threats that can impact pipeline integrity. IM regulations in 
49 CFR part 192 require that pipeline operators assess covered pipe 
segments periodically to detect degradation from threats that their 
analyses have indicated could affect the segment, though not all 
covered segments are subject to an SCC threat. SCC direct assessment 
(SCCDA) is an assessment technique that can be used to address this 
threat.
    Section 192.929 specifies requirements for gas transmission 
pipeline operators who use SCCDA for IM assessments. The requirements 
in Sec.  192.929 were promulgated before NACE Standard Practice SP0204-
2008 was published. They require that operators follow Appendix A3 of 
ASME/ANSI B31.8S. This appendix provides some guidance for conducting 
SCCDA, but is limited to SCC that occurs in high-pH environments. 
Experience has shown that pipelines also can experience SCC degradation 
in areas where the surrounding soil has a pH near neutral (referred to 
as near-neutral SCC). NACE Standard Practice SP0204-2008 addresses 
near-neutral SCC in addition to high-pH SCC. In addition, the NACE 
Standard provides technical guidelines and process requirements which 
are both more comprehensive and rigorous for conducting SCCDA than do 
Sec.  192.929 or ASME/ANSI B31.8S.
    The NACE standard provides additional guidance on:
     The factors that are important in the formation of SCC on 
a pipeline and what data should be collected;
     Additional factors, such as existing corrosion, which 
could cause SCC to form;
     Comprehensive data collection guidelines, including the 
relative importance of each type of data;
     Requirements to conduct close interval surveys of cathodic 
protection or other above-ground surveys to supplement the data 
collected during pre-assessment;
     Ranking factors to consider for selecting excavation 
locations for both near neutral and high pH SCC;
     Requirements on conducting direct examinations, including 
procedures for collecting environmental data, preparing the pipe 
surface for examination, and conducting Magnetic Particle Inspection 
(MPI) examinations of the pipe; and
     Post assessment analysis of results to determine SCCDA 
effectiveness and assure continual improvement.
    NACE SP0204-2008 provides comprehensive guidelines on conducting 
SCCDA which are commensurate with the state of the art. It is more 
comprehensive in scope than Appendix A3 of ASME/ANSI B31.8S. PHMSA has 
concluded the quality and consistency of SCCDA conducted under IM 
requirements would be improved by requiring the use of NACE SP0204-
2008. Revisions to Sec.  192.929 are proposed to address these issues.
    Sec.  192.933 What actions must be taken to address integrity 
issues?
    Section 192.933 specifies those injurious anomalies and defects 
which must be remediated, and the timeframe within which remediation 
must occur. PHMSA has determined that the existing rule has gaps, some 
injurious anomalies and defects are not identified in the rule as 
requiring remediation in a timely manner commensurate with their 
seriousness. The proposed rule would designate the following types of 
anomalies/defects as immediate

[[Page 20819]]

conditions: Metal loss greater than 80% of nominal wall thickness; 
indication of metal-loss affecting certain longitudinal seams; 
significant stress corrosion cracking; and selective seam weld 
corrosion. The proposed rule would also designate the following types 
of anomalies/defects as one-year conditions: Calculation of the 
remaining strength of the pipe shows a predicted failure pressure ratio 
at the location of the anomaly less than or equal to 1.25 for Class 1 
locations, 1.39 for Class 2 locations, 1.67 for Class 3 locations, and 
2.00 for Class 4 locations (comparable to the alternative design factor 
specified in Sec.  192.620(a)); area of general corrosion with a 
predicted metal loss greater than 50% of nominal wall; predicted metal 
loss greater than 50% of nominal wall that is located at a crossing of 
another pipeline, or is in an area with widespread circumferential 
corrosion, or is in an area that could affect a girth weld; gouge or 
groove greater than 12.5% of nominal wall; and any indication of crack 
or crack-like defect other than an immediate condition.
    The methods specified in the IM rule to calculate predicted failure 
pressure are explicitly not valid if metal exceeds 80% of wall 
thickness. Corrosion affecting a longitudinal seam, especially 
associated with seam types that are known to be susceptible to latent 
manufacturing defects such as the failed pipe at San Bruno, and 
selective seam weld corrosion, are known time sensitive integrity 
threats. Stress corrosion cracking is listed in ASME/ANSI B31.8S as an 
immediate repair condition, which is not reflected in the current IM 
regulations. PHMSA proposes to add requirements to address these gaps.
    With respect to SCC, PHMSA has incorporated repair criteria to 
address NTSB recommendation P-12-3 that resulted from the investigation 
of the Marshall, Michigan crude oil accident. From its investigation, 
the NTSB recommended that PHMSA revise Sec.  195.452 to clearly state 
(1) when an engineering assessment of crack defects, including 
environmentally assisted cracks, must be performed; (2) the acceptable 
methods for performing these engineering assessments, including the 
assessment of cracks coinciding with corrosion with a safety factor 
that considers the uncertainties associated with sizing of crack 
defects; (3) criteria for determining when a probable crack defect in a 
pipeline segment must be excavated and time limits for completing those 
excavations; (4) pressure restriction limits for crack defects that are 
not excavated by the required date; and (5) acceptable methods for 
determining crack growth for any cracks allowed to remain in the pipe, 
including growth caused by fatigue, corrosion fatigue, or stress 
corrosion cracking as applicable (NTSB recommendation P-12-3). Although 
the recommendation was focused on part 195, the issue applies to gas 
pipelines regulated under part 192. PHMSA proposes to allow the use of 
engineering assessment to evaluate if SCC is significant (and thus 
categorized as an ``immediate'' condition), or not significant (and 
thus categorized as a ``one-year'' condition), but that an engineering 
assessment not be allowed to justify not remediating any known 
indications of SCC. Further, PHMSA proposes to adopt the definition of 
significant SCC from NACE SP0204-2008.
    The current rule includes no explicit metal loss repair criteria 
for one-year conditions, other than one immediate condition. The rule 
does direct operators to use Figure 4 in ASME B31.8S to determine non-
immediate metal loss repair criteria. PHMSA proposes to repeal the 
reference to Figure 4, and explicitly include selected metal loss 
repair conditions in the one-year criteria. These new criteria are 
consistent with similar criteria currently invoked in the hazardous 
liquid integrity management rule at 40 CFR 195.452(h). In addition, 
PHMSA proposes to incorporate safety factors commensurate with the 
class location in which the pipeline is located, to include predicted 
failure pressure less than or equal to 1.25 times MAOP for Class 1 
locations, 1.39 times MAOP for Class 2 locations, 1.67 times MAOP for 
Class 3 locations, and 2.00 times MAOP for Class 4 locations in HCAs. 
Lastly, in response to the lessons learned from the Marshall, Michigan 
rupture, PHMSA proposes to include any crack or crack-like defect that 
does not meet the proposed immediate criteria, as a one year condition.
    In addition, as a result of its investigation of the Marshall, 
Michigan crude oil spill, the NTSB recommended that PHMSA revise Sec.  
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 (NTSB recommendation P-12-4). Although the 
recommendation was focused on part 195, the issue applies to gas 
pipelines regulated under part 192. Accordingly, PHMSA proposes to 
amend paragraph (b) of Sec.  192.933 to require that operators notify 
PHMSA whenever the operator cannot obtain sufficient information to 
determine if a condition presents a potential threat to the integrity 
of the pipeline, within 180 days of completing the assessment.
    Lastly, PHMSA proposes to require that pipe and material properties 
used in remaining strength calculations must be documented in reliable, 
traceable, verifiable, and complete records. If such records are not 
available, pipe and material properties used in the remaining strength 
calculations would be required to be based on properties determined and 
documented in accordance with Sec.  192.607.
    Sec.  192.935 What additional preventive and mitigative measures 
must an operator take?
    Section 192.935 requires an operator to take additional measures 
beyond those already required by part 192 to prevent a pipeline failure 
and to mitigate the consequences of a pipeline failure in a high 
consequence area (HCA). An operator must conduct a risk analysis to 
identify the additional measures to protect the high consequence area 
and improve public safety. As discussed above, PHMSA proposes to amend 
Sec.  192.917 to clarify the guidance for risk analyses operators use 
to evaluate and select additional preventive and mitigative measures. 
In addition, PHMSA has determined that some additional prescriptive 
preventive and mitigative measures are needed to assure that public 
safety is enhanced in HCAs and affords greater protections for HCAs. 
This proposed rule would expand the listing of example preventive and 
mitigative measures operators must consider, require that seismicity be 
analyzed to mitigate the threat of outside force damage, and would add 
specific enhanced measures for managing external corrosion and internal 
corrosion inside HCAs.
    With respect to additional preventive and mitigative measures 
operators must consider, PHMSA proposes to specify that preventive and 
mitigative measures include (i) correction of the root causes of past 
incidents in order to prevent recurrence, (ii) adequate operations and 
maintenance processes, (iii) adequate resources for successful 
execution of safety related activities, (iv) additional right-of-way 
patrols, (v) hydrostatic tests in areas where material has quality 
issues or lost records, (vi) tests to determine material mechanical and 
chemical properties for unknown properties that are needed to assure 
integrity or substantiate MAOP evaluations including material property 
tests from removed pipe that is

[[Page 20820]]

representative of the in-service pipeline, (vii) re-coating of damaged, 
poorly performing, or disbonded coatings, and (viii) additional depth-
of-cover survey at roads, streams and rivers, among others. These 
example preventive and mitigative measures do not alter the fundamental 
requirement to identify and implement preventive and mitigative 
measures, but do provide additional guidance and clarify PHMSA's 
expectations with this important aspect of integrity management.
    Section 29 of the Act requires operators to consider seismicity 
when evaluating threats. Accordingly, PHMSA proposes to include 
seismicity of the area in evaluating preventive and mitigative measures 
with respect to the threat of outside force damage.
    With respect to internal corrosion and external corrosion, PHMSA 
proposes to add new paragraphs (f) and (g) to Sec.  192.935 to specify 
that an operator must enhance its corrosion control program in HCAs to 
provide additional protections from the threat of corrosion. More 
specifically, operators would be required to conduct periodic close-
interval surveys, coating surveys, interference surveys, and gas-
quality monitoring inside HCAs. The requirements would include specific 
minimum performance standards for these activities.
    Lastly, to conform to the revised definition of ``electrical 
survey,'' the use of that term in Sec.  192.935 would be replaced with 
``indirect assessment'' to accommodate other techniques in addition to 
close-interval surveys.
    Sec.  192.937 What is a continual process of evaluation and 
assessment to maintain a pipeline's integrity?
    Section 192.937 requires that operators continue to periodically 
assess HCA segments and periodically evaluate the integrity of each 
covered pipeline segment. PHMSA has determined that conforming 
amendments would be needed to implement, and be consistent with, the 
changes discussed above for Sec. Sec.  192.917, 192.921, 192.933, and 
192.935. The proposed rule would require that the continual process of 
evaluation and assessment implement and be consistent with data 
integration and risk assessment information in order to identify the 
threats specific to each HCA segment, including interacting threats, 
and the risk represented by these threats (Sec.  192.917), selection 
and use of assessment methods (Sec.  192.921), decisions about 
remediation (Sec.  192.933), and identify additional preventive and 
mitigative measures (Sec.  192.935) to avert or reduce threats to 
acceptable levels.
    Sec.  192.939 What are the required reassessment intervals?
    Section 192.939 specifies reassessment intervals for pipelines 
subject to integrity management requirements. Section 5 of the Act 
includes a technical correction that clarified that periodic 
reassessments must occur, at a minimum of once every 7 calendar years, 
but that the Secretary may extend such deadline for an additional 6 
months if the operator submits written notice to the Secretary with 
sufficient justification of the need for the extension. PHMSA would 
expect that any justification, at a minimum, would need to demonstrate 
that the extension does not pose a safety risk. By this rulemaking, 
PHMSA intends to codify this technical correction. The proposed rule 
would implement this statutory requirement.
    Sec.  192.941 What is a low stress reassessment?
    Section 192.941, among other requirements, specifies that, to 
address the threat of external corrosion on cathodically protected pipe 
in a HCA segment, an operator must perform an electrical survey (i.e. 
indirect examination tool/method) at least every 7 years on the HCA 
segment. PHMSA proposes to make conforming edits to the language of 
this requirement to accommodate the revised definition of the term 
``electrical survey.'' To conform to the revised definition of 
``electrical survey,'' the use of that term in Sec.  192.941 would be 
replaced with ``indirect assessment'' to accommodate other techniques 
in addition to close-interval surveys.

Appendix A to Part 192--Records Retention Schedule for Transmission 
Pipelines

    As discussed under Sec.  192.13, above, the proposed rule would 
more clearly articulate the requirements for records preparation and 
retention for transmission pipelines and to require that records be 
reliable, traceable, verifiable, and complete. New appendix A to part 
192 provides specific requirements and records retention periods.

Appendix D to Part 192--Criteria for Cathodic Protection and 
Determination of Measurements

    Appendix D to part 192 specifies requirements for cathodic 
protection of steel, cast iron & ductile pipelines. PHMSA has 
determined that this guidance needs to be updated to incorporate 
lessons learned since this appendix was first promulgated in 1971. The 
proposed rule would update appendix D accordingly by eliminating 
outdated guidance on cathodic protection and interpretation of voltage 
measurement to better align with current standards.

Appendix E to Part 192--Guidance on Determining High Consequence Areas 
and on Carrying out Requirements in the Integrity Management Rule

    Appendix E to part 192 provides guidance for preventive and 
mitigative measures for HCA segment subject to subpart O. PHMSA 
proposes to make conforming edits to the language in this appendix to 
accommodate the revised definition of the term ``electrical survey.'' 
To conform to the revised definition of ``electrical survey,'' the use 
of that term in Appendix E would be replaced with ``indirect 
assessment'' to accommodate other techniques in addition to close-
interval surveys.

Appendix F to Part 192--Criteria for Conducting Integrity Assessments 
Using Guided Wave Ultrasonic Testing (GWUT)

    As discussed under Sec.  192.941 above, a new appendix F to part 
192 is proposed to provide specific requirements and acceptance 
criteria for the use of GWUT as an integrity assessment method. 
Operators must apply all 18 criteria defined in Appendix F to use GWUT 
as an integrity assessment method. If an operator applied GWUT 
technology in a manner that does not conform to Appendix F, it would be 
considered ``other technology'' in Sec. Sec.  192.710, 192.921, and 
192. 937.

VI. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192, 
193, and 195 all or parts of more than 60 standards and specifications 
developed and published by standard developing organizations (SDOs). In 
general, SDOs update and revise their published standards every 3 to 5 
years to reflect modern technology and best technical practices.
    The National Technology Transfer and Advancement Act of 1995 (Pub. 
L. 104-113) directs Federal agencies to use voluntary consensus 
standards in lieu of government-written standards whenever possible. 
Voluntary consensus standards are standards developed or adopted by 
voluntary bodies that develop, establish, or coordinate technical 
standards using agreed-upon procedures. In addition, Office of 
Management and Budget (OMB) issued OMB Circular A-119 to implement 
Section 12(d) of Public Law 104-113 relative to the utilization of 
consensus technical standards by

[[Page 20821]]

Federal agencies. This circular provides guidance for agencies 
participating in voluntary consensus standards bodies and describes 
procedures for satisfying the reporting requirements in Public Law 104-
113.
    In accordance with the preceding provisions, PHMSA has the 
responsibility for determining, via petitions or otherwise, which 
currently referenced standards should be updated, revised, or removed, 
and which standards should be added to 49 CFR parts 192, 193, and 195. 
Revisions to incorporated by reference materials in 49 CFR parts 192, 
193, and 195 are handled via the rulemaking process, which allows for 
the public and regulated entities to provide input. During the 
rulemaking process, PHMSA must also obtain approval from the Office of 
the Federal Register to incorporate by reference any new materials.
    On January 3, 2012, President Obama signed the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90. 
Section 24 states: ``Beginning 1 year after the date of enactment of 
this subsection, the Secretary may not issue guidance or a regulation 
pursuant to this chapter that incorporates by reference any documents 
or portions thereof unless the documents or portions thereof are made 
available to the public, free of charge, on an Internet Web site.'' 49 
U.S.C. 60102(p).
    On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 60102(p) to 
replace ``1 year'' with ``3 years'' and remove the phrases ``guidance 
or'' and ``, on an Internet Web site.'' This resulted in the current 
language in 49 U.S.C. 60102(p), which now reads as follows:
    ``Beginning 3 years after the date of enactment of this subsection, 
the Secretary may not issue a regulation pursuant to this chapter that 
incorporates by reference any documents or portions thereof unless the 
documents or portions thereof are made available to the public, free of 
charge.''
    Further, the Office of the Federal Register issued a November 7, 
2014, rulemaking (79 FR 66278) that revised 1 CFR 51.5 to require that 
agencies detail in the preamble of a proposed rulemaking the ways the 
materials it proposes to incorporate by reference are reasonably 
available to interested parties, or how the agency worked to make those 
materials reasonably available to interested parties. In relation to 
this proposed rulemaking, PHMSA has contacted each SDO and has 
requested a hyperlink to a free copy of each standard that has been 
proposed for incorporation by reference. Access to these standards will 
be granted until the end of the comment period for this proposed 
rulemaking. Access to these documents can be found on the PHMSA Web 
site at the following URL: http://www.phmsa.dot.gov/pipeline/regs under 
``Standards Incorporated by Reference.''
    Consistent with the proposed amendments in this document, PHMSA 
proposes to incorporate by reference the following materials identified 
as follows:
     API Standard 1163-2005, ``In-line Inspection Systems 
Qualification Standards.''--This Standard serves as an umbrella 
document to be used with and complement companion standards. NACE 
RP0102 Standard Recommended Practice, In-Line Inspections of Pipelines; 
and ASNT ILI-PQ In-Line Inspection Personnel Qualification & 
Certification all have been developed enabling service providers and 
pipeline operators to provide rigorous processes that will consistently 
qualify the equipment, people, processes and software utilized in the 
in-line inspection industry.
     NACE Standard Practice 0102-2010, ``Inline Inspection of 
Pipelines.''--This standard is intended for use by individuals and 
teams planning, implementing, and managing ILI projects and programs. 
The incorporation of this standard into the Federal pipeline safety 
regulations would promote a higher level of safety by establishing 
consistent standards to qualify the equipment, people, processes, and 
software utilized by the ILI industry.
     NACE Standard Practice 0204-2008, ``Stress Corrosion 
Cracking Direct Assessment.''--The standard practice for SCCDA 
presented in this standard addresses the situation in which a pipeline 
company has identified a portion of its pipeline as an area of interest 
with respect to SCC based on its history, operations, and risk 
assessment process and has decided that direct assessment is an 
appropriate approach for integrity assessment. This standard provides 
guidance for managing SCC by selecting potential pipeline segments, 
selecting dig sites within those segments, inspecting the pipe, 
collecting and analyzing data during the dig, establishing a mitigation 
program, defining the reevaluation interval, and evaluating the 
effectiveness of the SCCDA process.
     NACE Standard Practice 0206-2006, ``International 
Corrosion Direct Assessment Methodology for Pipelines Carrying Normally 
Dry Natural Gas.'' This standard covers the NACE internal corrosion 
direct assessment (ICDA) process for normally dry natural gas pipeline 
systems. This standard is intended to serve as a guide for applying the 
NACE DG-ICDA process on natural gas pipeline systems that meet the 
feasibility requirements of Paragraph 3.3 of this standard.
     ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel 
Qualification and Certification.'' The ASNT standard provides for 
qualification and certification requirements that are not addressed in 
part 192. The incorporation of this standard into the Federal pipeline 
safety regulations would promote a higher level of safety by 
establishing consistent standards to qualify the equipment, people, 
processes, and software utilized by the ILI industry.
     Battelle's Experience with ERW and Flash Welding Seam 
Failures: Causes and Implications (Task 1.4). This report presents an 
evaluation of the database dealing with failures originating in 
electric resistance welds (ERW) and flash weld (FW) seam defects as 
quantified by Battelle's archives and the related literature.
     Battelle Memorial Institute, ``Models for Predicting 
Failure Stress Levels for Defects Affecting ERW and Flash-Welded 
Seams'' (Subtask 2.4). This document presents an analysis of two known 
defect assessment methods in an effort to find suitable ways to 
satisfactorily predict the failure stress levels of defects in or 
adjacent to ERW or flash-welded line pipe seams.
     Battelle Final Report No. 13-021, ``Predicting Times to 
Failures for ERW Seam Defects that Grow by Pressure Cycle Induced 
Fatigue (Subtask 2.5).'' The work described in this report is part of a 
comprehensive study of ERW seam integrity and its impact on pipeline 
safety. The objective of this part of the work is to identify 
appropriate means for predicting the remaining lives of defects that 
remain after a seam integrity assessment and that may become enlarged 
by pressure-cycle-induced fatigue.
     Battelle Memorial Institute, ``Final Summary Report and 
recommendations for the Comprehensive Study to Understand Longitudinal 
ERW Seam Failures--Phase 1'' (Task 4.5).--This report summarizes work 
completed as part of a comprehensive project that resulted from a 
contract with Battelle, working with Kiefner and Associates (KAI) and 
Det Norske Veritas (DNV) as subcontractors, to address the concerns 
identified in NTSB recommendation (P-09-1) regarding the safety and 
performance of ERW pipe.

[[Page 20822]]

VII. Regulatory Analysis and Notices

    This proposed rule is published under the authority of the Federal 
Pipeline Safety 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. The amendments to the requirements for petroleum 
gas pipelines addressed in this rulemaking are issued under this 
authority.

Executive Orders 12866 and 13563, and DOT Policies and Procedures

    This proposed rule is a significant regulatory action under section 
3(f) of Executive Order 12866 and, therefore, was reviewed by the 
Office of Management and Budget. This proposed rule is significant 
under the Regulatory Policies and Procedures of the Department of 
Transportation.

    (44 FR 11034, February 26, 1979).

    Executive Orders 12866 and 13563 require that proposed rules deemed 
``significant'' include a Regulatory Impact Analysis, and that this 
analysis requires quantified estimates of the benefits and costs of the 
rule. PHMSA is providing the PRIA for this proposed rule simultaneously 
with this document, and it is available in the docket.
    PHMSA estimates the total present value of benefits from the 
proposed rule to be approximately $3,234 to $3,738 million \39\ using a 
7% discount rate ($4,050 to $4,663 million using a 3% discount rate) 
and the present value of costs to be approximately $597 million using a 
7% discount rate ($711 million using a 3% discount rate). The table in 
the executive summary provides a detailed estimate of the average 
annual costs and benefits for each major topic area.
---------------------------------------------------------------------------

    \39\ Range reflects uncertainty in defect failure rates for 
Topic Area 1.
---------------------------------------------------------------------------

Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA), as amended by the Small 
Business Regulatory Flexibility Fairness Act of 1996, requires Federal 
regulatory agencies to prepare an Initial Regulatory Flexibility 
Analysis (IFRA) for any proposed rule subject to notice-and-comment 
rulemaking under the Administrative Procedure Act unless the agency 
head certifies that the making will not have a significant economic 
impact on a substantial number of small entities. PHMSA has data on gas 
transmission pipeline operators affected by the proposed rule. However, 
PHMSA does not have data on currently unregulated gas gathering 
pipeline operators. Therefore, PHMSA prepared an IFRA which is 
available in the docket for the rulemaking.

Executive Order 13175

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

Paperwork Reduction Act

    Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide 
interested members of the public and affected agencies with an 
opportunity to comment on information collection and recordkeeping 
requests. PHMSA estimates that the proposals in this rulemaking will 
impact the information collections described below.
    Based on the proposals in this rule, PHMSA will submit an 
information collection revision request to OMB for approval based on 
the requirements in this proposed rule. The information collection is 
contained in the pipeline safety regulations, 49 CFR parts 190 through 
199. The following information is provided for each information 
collection: (1) Title of the information collection; (2) OMB control 
number; (3) Current expiration date; (4) Type of request; (5) Abstract 
of the information collection activity; (6) Description of affected 
public; (7) Estimate of total annual reporting and recordkeeping 
burden; and (8) Frequency of collection. The information collection 
burden for the following information collections are estimated to be 
revised as follows:
    1. Title: Recordkeeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 04/30/2018.
    Abstract: A person owning or operating a natural gas pipeline 
facility is required to maintain records, make reports, and provide 
information to the Secretary of Transportation at the Secretary's 
request. Based on the proposed revisions in this rule, PHMSA estimates 
that 100 new Type A, Area 2 gas gathering pipeline operators ~ (2200 
Type A, Area 2 miles w/o prior regulation/22) will be new to these 
requirements. PHMSA estimates that it will take these 100 operators 6 
hours to create and maintain records associated with Emergency Planning 
requirements. Therefore, PHMSA expects to add 100 responses and 600 
hours to this information collection as a result of the provisions in 
the proposed rule.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 12,400.
    Total Annual Burden Hours: 941,054.
    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: 7/31/2017.
    Abstract: 49 U.S.C. 60102 requires each operator of a pipeline 
facility (except master meter operators) to submit to 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 hazards to life, property or the 
environment. Based on the proposed revisions in this rule, PHMSA 
estimates that an additional 71,109 miles of pipe will become subject 
to the safety related condition reporting requirements. PHMSA estimates 
that such reports will be submitted at a rate of 0.23 reports per 1,000 
miles. PHMSA expects that, collectively, Type A, Area 2 lines will 
submit approximately 16 reports on an annual basis. As a result, PHMSA 
is adding an additional 16 responses and 96 burden hours to this 
information collection.
    Affected Public: Operators of Natural Gas, Hazardous Liquid, and 
Liquefied Natural Gas pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 158.
    Total Annual Burden Hours: 948.
    Frequency of Collection: On occasion.

    3. Title: Pipeline Integrity Management in High Consequence Areas 
Gas Transmission Pipeline Operators.
    OMB Control Number: 2137-0610.
    Current Expiration Date: 3/31/2016.
    Abstract: This information collection request pertains to Gas 
Transmission operators jurisdictional to 49 CFR part 192 subpart O--Gas 
Transmission Integrity Management Program. PHMSA is proposing that 
operators subject to Integrity Management requirements provide PHMSA 
notice when 180 days is insufficient to conduct an integrity assessment 
following the discovery of a condition (192.933). PHMSA estimates that 
20% of the 721 operators (721*.2 =

[[Page 20823]]

144 operators) will file such a notification. PHMSA estimates that each 
notification will take about 30 minutes. Based on this provision, PHMSA 
proposes to add 144 responses and 72 hours to this information 
collection.
    Affected Public: Gas Transmission operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 877.
    Total Annual Burden Hours: 1,018,879.
    Frequency of Collection: On occasion.

    4. Title: Incident and Annual Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: 10/31/2017.
    Abstract: This information collection covers the collection of 
information from Gas pipeline operators for Incidents and Annual 
reports. PHMSA is revising the Gas Transmission Incident report to 
incorporate Moderate Consequence Areas and to address Gathering line 
operators that are only subject to reporting. PHMSA estimates that 
operators of currently exempt gas gathering pipelines will have to 
submit incident reports for 27.5 incidents over the next three years, 
an average of 9 reports annually. However, the proposed rule is 
expected to reduce the number of incidents by at least 10 each year 
which would result in a cumulative increase of zero incidents.
    PHMSA is also revising the Gas Transmission and Gas Gathering 
Annual Report to collect additional information including mileage of 
pipe subject to the IVP and MCA criteria. Based on the proposed 
revisions, PHMSA estimates that an additional annual 500 reports to the 
current 1,440 reports will be submitted based on the required reporting 
of non-regulated gathering lines and gathering lines now subject to 
certain safety provisions. Further PHMSA estimates that the Annual 
report will require an additional 5 hours/report to the currently 
approved 42 hours due to collection of MCA data and IVP provisions. 
Therefore the overall burden allotted for the reporting of Gas annual 
reports will increase by 30,700 hours from 60,480 hours (42 hours*1,440 
reports) to 91,180 hours (47 hours*1,940 reports).
    As a result of the provisions mentioned above, the burden for this 
information collection will increase by 500 responses and 30,700 burden 
hours.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 12,664.
    Total Annual Burden Hours: 103,182
    Frequency of Collection: On occasion.

    5. Title: National Registry of Pipeline and LNG Operators.
    OMB Control Number: 2137-0627.
    Current Expiration Date: 05/31/2018.
    Abstract: The National Registry of Pipeline and LNG Operators 
serves as the storehouse for the reporting requirements for an operator 
regulated or subject to reporting requirements under 49 CFR part 192, 
193, or 195. This registry incorporates the use of two forms. The forms 
for assigning and maintaining Operator Identification (OPID) 
information are the Operator Assignment Request Form (PHMSA F 1000.1) 
and Operator Registry Notification Form (PHMSA F 1000.2). PHMSA plans 
to make revisions to the form/instructions to account for ``reporting 
only'' gathering operators. PHMSA estimates that 500 gas gathering 
operators will require a new OPID. Based on a 3 year average this 
results in an additional 167 responses a year initially. In addition to 
the OPID assignment, PHMSA estimates that 123 gathering operators will 
submit approx. 1 notification per year. PHMSA estimates that each 
submission will take approx. 1 hour to complete. Based on these 
provisions, PHMSA expects this information collection to increase by 
290 responses and 290 burden hours.
    Affected Public: Operators of Natural Gas, Hazardous Liquid, and 
Liquefied Natural Gas pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 920.
    Total Annual Burden Hours: 920.
    Frequency of Collection: On occasion.

    Requests for copies of these information collections should be 
directed to Angela Dow or Cameron Satterthwaite, Office of Pipeline 
Safety (PHP-30), Pipeline 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.
    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 June 7, 2016.

Unfunded Mandates Reform Act of 1995

    An evaluation of Unfunded Mandates Reform Act (UMRA) considerations 
is performed as part of the Preliminary Regulatory Impact Assessment. 
The estimated costs to the States are approximately $1.3 million per 
year and are significantly less than the UMRA criterion of $151 million 
per year ($100 million, adjusted for inflation). The estimated costs to 
the private sector are in excess of the UMRA criterion of $151 million 
per year. A copy of the Preliminary Regulatory Impact Assessment is 
available for review in the docket.

National Environmental Policy Act

    PHMSA analyzed this proposed 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 1500-1508), 
and DOT Order 5610.1C, and has preliminarily determined this action 
will not significantly affect the quality of the human environment. The 
Environmental Assessment for this proposed action is in the docket.

Executive Order 13132

    PHMSA has analyzed this proposed rule according to Executive Order 
13132 (``Federalism''). The proposed rule does not have a substantial 
direct effect on the States, the relationship between the national 
government and the States, or the distribution of power and 
responsibilities among the various levels of government. This proposed 
rule does not impose substantial direct compliance costs on State and 
local governments. This proposed rule would not preempt state law for 
intrastate pipelines. Therefore, the consultation and funding 
requirements of Executive Order 13132 do not apply.

Executive Order 13211

    This proposed rule is not a ``significant energy action'' under 
Executive Order 13211 (Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use). It is not 
likely to have a significant adverse effect on

[[Page 20824]]

supply, distribution, or energy use. Further, the Office of Information 
and Regulatory Affairs has not designated this proposed rule as a 
significant energy action.

Privacy Act Statement

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

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 number contained in the heading 
of this document can be used to cross-reference this action with the 
Unified Agenda.

List of Subjects

49 CFR Part 191

    Pipeline reporting requirements, Integrity Management, Pipeline 
safety, Gas gathering.

49 CFR Part 192

    Incorporation by reference, Pipeline Safety, Fire prevention, 
Security measures.
    In consideration of the foregoing, PHMSA proposes to amend 49 CFR 
parts 191 and 192 as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; 
ANNUAL, INCIDENT, AND OTHER REPORTING

0
1. The authority citation for part 191 is revised to read as follows:

    Authority:  49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 
60118, 60124, 60132, and 60139; and 49 CFR 1.97.

0
2. In Sec.  191.1, paragraphs (a) and (b)(2) and (3) are revised, 
paragraph (b)(4) is deleted, and paragraph (c) is added to read as 
follows:


Sec.  191.1  Scope.

    (a) This part prescribes requirements for the reporting of 
incidents, safety-related conditions, exceedances of maximum allowable 
operating pressure (MAOP), annual pipeline summary data, National 
Operator Registry information, and other miscellaneous conditions by 
operators of gas pipeline facilities located in the United States or 
Puerto Rico, including pipelines within the limits of the Outer 
Continental Shelf as that term is defined in the Outer Continental 
Shelf Lands Act (43 U.S.C. 1331). This part applies to offshore 
gathering lines and to onshore gathering lines, whether designated as 
``regulated onshore gathering lines'' or not (as determined in Sec.  
192.8 of this chapter).
    (b) * * *
    (2) Pipelines on the Outer Continental Shelf (OCS) that are 
producer-operated and cross into State waters without first connecting 
to a transporting operator's facility on the OCS, upstream (generally 
seaward) of the last valve on the last production facility on the OCS. 
Safety equipment protecting PHMSA-regulated pipeline segments is not 
excluded. Producing operators for those pipeline segments upstream of 
the last valve of the last production facility on the OCS may petition 
the Administrator, or designee, for approval to operate under PHMSA 
regulations governing pipeline design, construction, operation, and 
maintenance under 49 CFR 190.9; or
    (3) Pipelines on the Outer Continental Shelf upstream of the point 
at which operating responsibility transfers from a producing operator 
to a transporting operator.
    (c) Sections 191.22(b) and 191.29 do not apply to gathering of 
gas--
    (1) Through a pipeline that operates at less than 0 psig (0 kPa);
    (2) Through an onshore pipeline that is not a regulated onshore 
gathering line (as determined in Sec.  192.8 of this chapter); and
    (3) Within inlets of the Gulf of Mexico, except for the 
requirements in Sec.  192.612.
0
3. In Sec.  191.23, revise paragraph (a)(5), add paragraph (a)(9), and 
revise paragraph (b)(4) to read as follows:


Sec.  191.23  Reporting safety-related conditions.

    (a) * * **
    (5) Any malfunction or operating error that causes the pressure of 
a distribution or gathering pipeline or LNG facility that contains or 
processes gas or LNG to rise above its maximum allowable operating 
pressure (or working pressure for LNG facilities) plus the margin 
(build-up) allowed for operation of pressure limiting or control 
devices.
* * * * *
    (9) For transmission pipelines, each exceedance of the maximum 
allowable operating pressure that exceeds the margin (build-up) allowed 
for operation of pressure-limiting or control devices as specified in 
Sec. Sec.  192.201, 192.620(e), and 192.739, as applicable.
    (b) * * *
    (4) Is corrected by repair or replacement in accordance with 
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for 
conditions under paragraph (a)(1) of this section other than localized 
corrosion pitting on an effectively coated and cathodically protected 
pipeline and any condition under paragraph (a)(9) of this section.
0
4. Section 191.25 is revised to read as follows:


Sec.  191.25  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec.  
191.23(a)(1) through (8) must be filed (received by the Associate 
Administrator, OPS) within five working days (not including Saturday, 
Sunday, or Federal Holidays) after the day a representative of the 
operator first determines that the condition exists, but not later than 
10 working days after the day a representative of the operator 
discovers the condition. Separate conditions may be described in a 
single report if they are closely related. Reports may be transmitted 
by electronic mail to InformationResourcesManager@dot.gov or by 
facsimile at (202) 366-7128.
    (b) Each report of a maximum allowable operating pressure 
exceedance meeting the requirements of criteria in Sec.  191.23(a)(9) 
for a gas transmission pipeline must be reported within five calendar 
days of the exceedance using the reporting methods and report 
requirements described in Sec.  191.25(c).
    (c) Reports may be filed by emailing information to 
InformationResourcesManager@dot.gov.or by fax to (202) 366-7128. The 
report must be headed ``Safety-Related Condition Report'' or for Sec.  
191.23(a)(9) ``Maximum Allowable Operating Pressure Exceedances'', and 
provide the following information:
    (1) Name, principal address, and operator identification number 
(OPID) of operator.
    (2) Date of report.
    (3) Name, job title, and business telephone number of person 
submitting the report.
    (4) Name, job title, and business telephone number of person who 
determined that the condition exists.
    (5) Date condition was discovered and date condition was first 
determined to exist.
    (6) Location of condition, with reference to the State (and town, 
city, or county) or Offshore site, and as appropriate, nearest street 
address, offshore platform, survey station number, milepost, landmark, 
or name of pipeline.
    (7) Description of the condition, including circumstances leading 
to its discovery, any significant effects of the

[[Page 20825]]

condition on safety, and the name of the commodity transported or 
stored.
    (8) The corrective action taken (including reduction of pressure or 
shutdown) before the report is submitted and the planned follow-up 
future corrective action, including the anticipated schedule for 
starting and concluding such action.
0
4a. In Sec.  191.29, paragraph (c) is added to read as follows:


Sec.  191.29  National Pipeline Mapping System.

* * * * *
    (c) This section does not apply to gathering lines.

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

0
5. The authority citation for part 192 is revised to read as follows:

    Authority:  49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, 60116, 60118, 60137, and 60139; and 49 CFR 1.97.
0
6. In Sec.  192.3:
0
a. Add definitions for ``Close interval survey'', ``Distribution 
center'', and ``Dry gas or dry natural gas'' in alphabetical order;
0
b. Revise the definition of ``Electrical survey'';
0
c. Add definitions for ``Gas processing plant'' and ``Gas treatment 
facility,'' in alphabetical order;
0
d. Revise the definition of ``Gathering line'';
0
e. Add definitions for ``Hard spot'', ``In-line inspection (ILI)'', 
``In-line inspection tool or instrumented internal inspection device'', 
``Legacy construction techniques'', ``Legacy pipe'', ``Moderate 
consequence area'', ``Modern pipe'', ``Occupied site'', ``Onshore 
production facility/operation'', ``Significant seam cracking'', 
``Significant stress corrosion cracking'', in alphabetical order;
0
f. Revise the definition of ``Transmission line'' and its note; and
0
g. Add a definition for ``Wrinkle bend'' in alphabetical order.
    The additions and revisions to read as follows:


Sec.  192.3  Definitions.

* * * * *
    Close interval survey means a series of closely spaced pipe-to-
electrolyte potential measurements taken to assess the adequacy of 
cathodic protection or to identify locations where a current may be 
leaving the pipeline that may cause corrosion and for the purpose of 
quantifying voltage (IR) drops other than those across the structure 
electrolyte boundary.
* * * * *
    Distribution center means a location where gas volumes are either 
metered or have pressure or volume reductions prior to delivery to 
customers through a distribution line.
* * * * *
    Dry gas or dry natural gas means gas with less than 7 pounds of 
water per million (MM) cubic feet and not subject to excessive upsets 
allowing electrolytes into the gas stream.
    Electrical survey means a series of closely spaced measurements of 
the potential difference between two reference electrodes to determine 
where the current is leaving the pipe on ineffectively coated or bare 
pipelines.
* * * * *
    Gas processing plant means a natural gas processing operation, 
other than production processing, operated for the purpose of 
extracting entrained natural gas liquids and other associated non-
entrained liquids from the gas stream and does not include a natural 
gas processing plant located on a transmission line, commonly referred 
to as a straddle plant.
    Gas treatment facility means one or a series of gas treatment 
operations, operated for the purpose of removing impurities (e.g., 
water, solids, basic sediment and water, sulfur compounds, carbon 
dioxide, etc.) that is not associated with a processing plant or 
compressor station and is not on a transmission line.
    Gathering line (Onshore) means a pipeline, or a connected series of 
pipelines, and equipment used to collect gas from the endpoint of a 
production facility/operation and transport it to the furthermost point 
downstream of the endpoints described in paragraphs (1) through (4) of 
this definition:
    (1) The inlet of 1st gas processing plant, unless the operator 
submits a request for approval to the Associate Administrator of 
Pipeline Safety that demonstrates, using sound engineering principles, 
that gathering extends to a further downstream plant other than a plant 
located on a transmission line and the Associate Administrator of 
Pipeline Safety approves such request;
    (2) The outlet of gas treatment facility that is not associated 
with a processing plant or compressor station;
    (3) Outlet of the furthermost downstream compressor used to 
facilitate delivery into a pipeline, other than another gathering line; 
or
    (4) The point where separate production fields are commingled, 
provided the distance between the interconnection of the fields does 
not exceed 50 miles, unless the Associate Administrator of Pipeline 
Safety finds a longer separation distance is justified in a particular 
case (see Sec.  190.9 of this chapter).
    (5) Gathering may continue beyond the endpoints described in 
paragraphs (1) through (4) of this definition to the point gas is 
delivered into another pipeline, provided that it only does the 
following:
    (i) It delivers gas into another gathering line;
    (A) It does not leave the operator's facility surface property 
(owned or leased, not necessarily the fence line);
    (B) It does not leave an adjacent property owned or leased by 
another pipeline operator's property--where custody transfer takes 
place; or
    (C) It does not exceed a length of one mile, and it does not cross 
a state or federal highway or an active railroad; or
    (ii) It transports gas to production or gathering facilities for 
use as fuel, gas lift, or gas injection gas.
    (6) Pipelines that serve residential, commercial, or industrial 
customers that originate at a tap on gathering lines are not gathering 
lines; they are service lines and are commonly referred to as farm 
taps.
* * * * *
    Hard spot means steel pipe material with a minimum dimension 
greater than two inches (50.8 mm) in any direction and hardness greater 
than or equal to Rockwell 35 HRC (Brinnel 327 HB or Vickers 345 HV10).
* * * * *
    In-line inspection (ILI) means the inspection of a pipeline from 
the interior of the pipe using an in-line inspection tool, which is 
also called intelligent or smart pigging.
    In-line inspection tool or instrumented internal inspection device 
means a device or vehicle that uses a non-destructive testing technique 
to inspect the pipeline from the inside, which is also called an 
intelligent or smart pig.
    Legacy construction techniques mean usage of any historic, now-
abandoned, construction practice to construct or repair pipe segments, 
including any of the following techniques:
    (1) Wrinkle bends;
    (2) Miter joints exceeding three degrees;
    (3) Dresser couplings;
    (4) Non-standard fittings or field fabricated fittings (e.g., 
orange-peeled reducers) with unknown pressure ratings;
    (5) Acetylene welds;

[[Page 20826]]

    (6) Bell and spigots; or
    (7) Puddle welds.
    Legacy pipe means steel pipe manufactured using any of the 
following techniques, regardless of the date of manufacture:
    (1) Low-Frequency Electric Resistance Welded (LF-ERW);
    (2) Direct-Current Electric Resistance Welded (DC-ERW);
    (3) Single Submerged Arc Welded (SSAW);
    (4) Electric Flash Welded (EFW);
    (5) Wrought iron;
    (6) Pipe made from Bessemer steel; or
    (7) Any pipe with a longitudinal joint factor, as defined in Sec.  
192.113, less than 1.0 (such as lap-welded pipe) or with a type of 
longitudinal joint that is unknown or cannot be determined, including 
pipe of unknown manufacturing specification.
* * * * *
    Moderate consequence area means an onshore area that is within a 
potential impact circle, as defined in Sec.  192.903, containing five 
(5) or more buildings intended for human occupancy, an occupied site, 
or a right-of-way for a designated interstate, freeway, expressway, and 
other principal 4-lane arterial roadway as defined in the Federal 
Highway Administration's Highway Functional Classification Concepts, 
Criteria and Procedures, and does not meet the definition of high 
consequence area, as defined in Sec.  192.903. The length of the 
moderate consequence area extends axially along the length of the 
pipeline from the outermost edge of the first potential impact circle 
that contains either an occupied site, five (5) or more buildings 
intended for human occupancy, or a right-of-way for a designated 
interstate, freeway, expressway, or other principal 4-lane arterial 
roadway, to the outermost edge of the last contiguous potential impact 
circle that contains either an occupied site, five (5) or more 
buildings intended for human occupancy, or a right-of-way for a 
designated interstate, freeway, expressway, or other principal 4-lane 
arterial roadway.
    Modern pipe means any steel pipe that it is not legacy pipe, 
regardless of the date of manufacture, and has a longitudinal joint 
factor of 1.0 as defined in Sec.  192.113. Modern pipe refers to all 
pipe that is not legacy pipe.
* * * * *
    Occupied site means each of the following areas:
    (1) An outside area or open structure that is occupied by five (5) 
or more persons on at least 50 days in any twelve (12)-month period. 
(The days need not be consecutive.) Examples include but are not 
limited to, beaches, playgrounds, recreational facilities, camping 
grounds, outdoor theaters, stadiums, recreational areas near a body of 
water, or areas outside a rural building such as a religious facility; 
or
    (2) A building that is occupied by five (5) or more persons on at 
least five (5) days a week for ten (10) weeks in any twelve (12)-month 
period. (The days and weeks need not be consecutive.) Examples include, 
but are not limited to, religious facilities, office buildings, 
community centers, general stores, 4-H facilities, or roller skating 
rinks.
* * * * *
    Onshore production facility or onshore production operation means 
wellbores, equipment, piping, and associated appurtenances confined to 
the physical acts of extraction or recovery of gas from the earth and 
the initial preparation for transportation. Preparation for 
transportation does not necessarily mean the gas will meet ``pipeline 
quality'' specifications as may be commonly understood or contained in 
many contractual agreements. Piping as used in this definition may 
include individual well flow lines, equipment piping, and transfer 
lines between production operation equipment components. Production 
facilities terminate at the furthermost downstream point where: 
Measurement for the purposes of calculating minerals severance occurs; 
or there is commingling of the flow stream from two or more wells.
* * * * *
    Significant seam cracking means cracks or crack-like flaws in the 
longitudinal seam or heat affected zone of a seam weld where the 
deepest crack is greater than or equal to 10% of wall thickness or the 
total interacting length of the cracks is equal to or greater than 75% 
of the critical length of a 50% through-wall flaw that would fail at a 
failure pressure less than or equal to 110% of SMYS, as determined in 
accordance with fracture mechanics failure pressure evaluation methods 
(Sec. Sec.  192.624(c) and (d)) for the failure mode using conservative 
Charpy energy values of the crack-related conditions.
    Significant stress corrosion cracking means a stress corrosion 
cracking (SCC) cluster in which the deepest crack, in a series of 
interacting cracks, is greater than 10% of the wall thickness and the 
total interacting length of the cracks is equal to or greater than 75% 
of the critical length of a 50% through-wall flaw that would fail at a 
stress level of 110% of SMYS.
* * * * *
    Transmission line means a pipeline, other than a gathering line, 
that: transports gas from a gathering line or storage facility to a 
distribution center, storage facility, or large volume customer that is 
not down-stream from a distribution center; has an MAOP of 20 percent 
or more of SMYS; or transports gas within a storage field.
    Note: A large volume customer (factories, power plants, and 
institutional users of gas) may receive similar volumes of gas as a 
distribution center.
* * * * *
    Wrinkle bend. (1) Means a bend in the pipe that was formed in the 
field during construction such that the inside radius of the bend has 
one or more ripples with:
    (i) An amplitude greater than or equal to 1.5 times the wall 
thickness of the pipe, measured from peak to valley of the ripple; or
    (ii) With ripples less than 1.5 times the wall thickness of the 
pipe and with a wrinkle length (peak to peak) to wrinkle height (peak 
to valley) ratio under 12.
[GRAPHIC] [TIFF OMITTED] TP08AP16.000



[[Page 20827]]


D = The outside diameter of the pipe, in. (mm),
h = The crest-to-trough height of the ripple, in. (mm), and
S = The maximum operating hoop stress, psi (S/145, MPa).

0
7. In Sec.  192.5, paragraph (d) is added to read as follows:


Sec.  192.5  Class locations.

* * * * *
    (d) Records for transmission pipelines documenting class locations 
and demonstrating how an operator determined class locations in 
accordance with this section must be retained for the life of the 
pipeline.
0
8. Amend Sec.  192.7 by removing and reserving paragraph (b)(4) and 
adding paragraphs (b)(10), (g)(2) through (4), (k), and (l).
    The additions read as follows:


Sec.  192.7  What documents are incorporated by reference partly or 
wholly in this part?

* * * * *
    (b) * * *
    (10) API STD 1163-2005, ``In-Line Inspection Systems Qualification 
Standard,'' 1st edition, August 2001, (API STD 1163), IBR approved for 
Sec.  192.493.
* * * * *
    (g) * * *
    (2) NACE Standard Practice 0102-2010, ``Inline Inspection of 
Pipelines,'' Revised 2010, (NACE SP0102), IBR approved for Sec. Sec.  
192.150(a) and 192.493.
    (3) NACE Standard Practice 0204-2008, ``Stress Corrosion Cracking 
Direct Assessment,'' Revised 2008, (NACE SP0204), Reaffirmed 2008, IBR 
approved for Sec. Sec.  192.923(b)(3) and 192.929.
    (4) NACE Standard Practice 0206-2006, ``International Corrosion 
Direct Assessment Methodology for Pipelines Carrying Normally Dry 
Natural Gas,'' (NACE SP0206-2006), IBR approved for Sec. Sec.  
192.923(b)(2), 192.927(b), and 192.927(c).
* * * * *
    (k) American Society for Nondestructive Testing (ASNT), P.O. Box 
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone (800) 222-2768, 
https://www.asnt.org/.
    (1) ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel 
Qualification and Certification,'' 2010, (ANSI/ASNT ILI-PQ-2010), IBR 
approved for Sec.  192.493.
    (2) [Reserved]
    (l) Battelle Memorial Institute, 505 King Avenue, Columbus, OH 
43201, phone (800) 201-2011, http://www.battelle.org/.
    (1) Battelle's Experience with ERW and Flash Welding Seam Failures: 
Causes and Implications (Task 1.4), IBR approved for Sec.  192.624(c) 
and (d).
    (2) Battelle Memorial Institute, ``Models for Predicting Failure 
Stress Levels for Defects Affecting ERW and Flash-Welded Seams'' 
(Subtask 2.4), IBR approved for Sec.  192.624(c) and (d).
    (3) Battelle Final Report No. 13-021, ``Predicting Times to 
Failures for ERW Seam Defects that Grow by Pressure Cycle Induced 
Fatigue (Subtask 2.5), IBR approved for Sec.  192.624(c) and (d).
    (4) Battelle Memorial Institute, ``Final Summary Report and 
recommendations for the Comprehensive Study to Understand Longitudinal 
ERW Seam Failures--Phase 1'' (Task 4.5), IBR approved for Sec.  
192.624(c) and (d).
0
9. Section 192.8 is revised to read as follows:


Sec.  192.8  How are onshore gathering lines and regulated onshore 
gathering lines determined?

    (a) Each operator must determine and maintain records documenting 
the beginning and endpoints of each gathering line it operates using 
the definitions of onshore production facility (or onshore production 
operation), gas processing facility, gas treatment facility, and 
onshore gathering line as defined in Sec.  192.3 by [date 6 months 
after effective date of the final rule] or before the pipeline is 
placed into operation, whichever is later.
    (b) Each operator must determine and maintain records documenting 
the beginning and endpoints of each regulated onshore gathering line it 
operates as determined in Sec.  192.8(c) by [date 6 months after 
effective date of the final rule] or before the pipeline is placed into 
operation, whichever is later.
    (c) For purposes of part 191 of this chapter and Sec.  192.9, 
``regulated onshore gathering line'' means:
    (1) Each onshore gathering line (or segment of onshore gathering 
line) with a feature described in the second column that lies in an 
area described in the third column; and
    (2) As applicable, additional lengths of line described in the 
fourth column to provide a safety buffer:

----------------------------------------------------------------------------------------------------------------
                Type                           Feature                    Area                Safety buffer
----------------------------------------------------------------------------------------------------------------
A...................................  --Metallic and the MAOP   Area 1. Class 2, 3, or   None.
                                       produces a hoop stress    4 location (see Sec.
                                       of less than 20 percent   192.5).
                                       of SMYS. If the stress   Area 2. Class 1
                                       level is unknown, an      location with a
                                       operator must determine   nominal diameter of 8
                                       the stress level          inches or greater.
                                       according to the
                                       applicable provisions
                                       in subpart C of this
                                       part.
                                      --Non-metallic and the
                                       MAOP is more than 125
                                       psig (862 kPa).
B...................................  --Non-metallic and the    Area 1. Class 3, or 4    If the gathering line
                                       MAOP produces a hoop      location.                is in Area 2(b) or
                                       stress of less than 20   Area 2. An area within    2(c), the additional
                                       percent of SMYS. If the   a Class 2 location the   lengths of line extend
                                       stress level is           operator determines by   upstream and
                                       unknown, an operator      using any of the         downstream from the
                                       must determine the        following three          area to a point where
                                       stress level according    methods:.                the line is at least
                                       to the applicable        (a) A Class 2 location;   150 feet (45.7 m) from
                                       provisions in subpart C  (b) An area extending     the nearest dwelling
                                       of this part.             150 feet (45.7 m) on     in the area. However,
                                      --Non-metallic and thew    each side of the         if a cluster of
                                       MAOP is 125 psig (862     centerline of any        dwellings in Area 2(b)
                                       kPa) or less.             continuous 1 mile (1.6   or 2(c) qualifies a
                                                                 km) of pipeline and      line as Type B, the
                                                                 including more than 10   Type B classification
                                                                 but fewer than 46        ends 150 feet (45.7 m)
                                                                 dwellings; or.           from the nearest
                                                                (c) An area extending     dwelling in the
                                                                 150 feet (45.7 m) on     cluster.
                                                                 each side of the
                                                                 centerline of any
                                                                 continuous 1000 feet
                                                                 (305 m) of pipeline
                                                                 and including 5 or
                                                                 more dwellings..
----------------------------------------------------------------------------------------------------------------


[[Page 20828]]

0
10. In Sec.  192.9, paragraphs (c), (d), and (e) are revised and 
paragraph (f) is added to read as follows:


Sec.  192.9  What requirements apply to gathering lines?

* * * * *
    (c) Type A, Area 1 lines. An operator of a Type A, Area 1 regulated 
onshore gathering line must comply with the requirements of this part 
applicable to transmission lines, except the requirements in Sec. Sec.  
192.13, 192.150, 192.319, 192.461(f), 192.465(f), 192.473(c), 192.478, 
192.710, 192.713, and in subpart O of this part. However, an operator 
of a Type A, Area 1 regulated onshore gathering line in a Class 2 
location may demonstrate compliance with subpart N by describing the 
processes it uses to determine the qualification of persons performing 
operations and maintenance tasks.
    (d) Type A, Area 2 and Type B lines. An operator of a Type A, Area 
2 or Type B regulated onshore gathering line must comply with the 
following requirements:
    (1) If a line is new, replaced, relocated, or otherwise changed, 
the design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines;
    (2) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission 
lines;
    (3) Carry out a damage prevention program under Sec.  192.614;
    (4) Establish a public education program under Sec.  192.616;
    (5) Establish the MAOP of the line under Sec.  192.619;
    (6) Install and maintain line markers according to the requirements 
for transmission lines in Sec.  192.707;
    (7) Conduct leakage surveys in accordance with Sec.  192.706 using 
leak detection equipment and promptly repair hazardous leaks that are 
discovered in accordance with Sec.  192.703(c); and
    (8) For a Type A, Area 2 regulated onshore gathering line only, 
develop procedures, training, notifications, emergency plans and 
implement as described in Sec.  192.615.
    (e) If a regulated onshore gathering line existing on [effective 
date of the final rule] was not previously subject to this part, an 
operator has until [date two years after effective date of the final 
rule] to comply with the applicable requirements of this section, 
unless the Administrator finds a later deadline is justified in a 
particular case.
    (f) If, after [effective date of the final rule], a change in class 
location or increase in dwelling density causes an onshore gathering 
line to be a regulated onshore gathering line, the operator has one 
year for Type A, Area 2 and Type B lines and two years for Type A, Area 
1 lines after the line becomes a regulated onshore gathering line to 
comply with this section.
0
11. In Sec.  192.13, paragraphs (a) and (b) are revised and paragraphs 
(d) and (e) are added to read as follows:


Sec.  192.13  What general requirements apply to pipelines regulated 
under this part?

    (a) No person may operate a segment of pipeline listed in the first 
column that is readied for service after the date in the second column, 
unless:
    (1) The pipeline has been designed, installed, constructed, 
initially inspected, and initially tested in accordance with this part; 
or
    (2) The pipeline qualifies for use under this part according to the 
requirements in Sec.  192.14.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15 2007.
 this part did not apply until April 14,
 2006.
Regulated onshore gathering line to which   [date 1 year after effective
 this part did not apply until [effective    date of the final rule].
 date of the final rule].
All other pipelines.......................  March 12, 1971.
------------------------------------------------------------------------

    (b) No person may operate a segment of pipeline listed in the first 
column that is replaced, relocated, or otherwise changed after the date 
in the second column, unless the replacement, relocation or change has 
been made according to the requirements in this part.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15, 2007.
 this part did not apply until April 14,
 2006.
Regulated onshore gathering line to which   [date 1 year after effective
 this part did not apply until [effective    date of the final rule].
 date of the final rule].
All other pipelines.......................  November 12, 1970.
------------------------------------------------------------------------

* * * * *
    (d) Each operator of an onshore gas transmission pipeline must 
evaluate and mitigate, as necessary, risks to the public and 
environment as an integral part of managing pipeline design, 
construction, operation, maintenance, and integrity, including 
management of change. Each operator of an onshore gas transmission 
pipeline must develop and follow a management of change process, as 
outlined in ASME/ANSI B31.8S, section 11, that addresses technical, 
design, physical, environmental, procedural, operational, maintenance, 
and organizational changes to the pipeline or processes, whether 
permanent or temporary. A management of change process must include the 
following: reason for change, authority for approving changes, analysis 
of implications, acquisition of required work permits, documentation, 
communication of change to affected parties, time limitations, and 
qualification of staff.
    (e) Each operator must make and retain records that demonstrate 
compliance with this part.
    (1) Operators of transmission pipelines must keep records for the 
retention period specified in appendix A to part 192.
    (2) Records must be reliable, traceable, verifiable, and complete.
    (3) For pipeline material manufactured before [effective date of 
the final rule] and for which records are not available, each operator 
must re-establish pipeline material documentation in accordance with 
the requirements of Sec.  192.607.
0
12. Section 192.67 is added to subpart A to read as follows:


Sec.  192.67  Records: Materials.

    Each operator of transmission pipelines must acquire and retain for 
the life of the pipeline the original steel pipe manufacturing records 
that document tests, inspections, and attributes required by the 
manufacturing specification in effect at the time the pipe was 
manufactured, including, but not limited to, yield strength, ultimate 
tensile strength, and chemical composition of materials for pipe in 
accordance with Sec.  192.55.
0
13. Section 192.127 is added to subpart B to read as follows:


Sec.  192.127  Records: Pipe design.

    Each operator of transmission pipelines must make and retain for 
the life of the pipeline records documenting pipe design to withstand 
anticipated external pressures and loads in accordance with Sec.  
192.103 and determination of design pressure for steel pipe in 
accordance with Sec.  192.105.
0
14. In Sec.  192.150, paragraph (a) is revised to read as follows:


Sec.  192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each new

[[Page 20829]]

transmission line and each replacement of line pipe, valve, fitting, or 
other line component in a transmission line must be designed and 
constructed to accommodate the passage of instrumented internal 
inspection devices, in accordance with the requirements and 
recommendations in NACE SP0102-2010, section 7 (incorporated by 
reference, see Sec.  192.7).
* * * * *
0
15. Section 192.205 is added to subpart D to read as follows:


Sec.  192.205  Records: Pipeline components.

    Each operator of transmission pipelines must acquire and retain 
records documenting the manufacturing standard and pressure rating to 
which each valve was manufactured and tested in accordance with this 
subpart. Flanges, fittings, branch connections, extruded outlets, 
anchor forgings, and other components with material yield strength 
grades of 42,000 psi or greater must have records documenting the 
manufacturing specification in effect at the time of manufacture, 
including, but not limited to, yield strength, ultimate tensile 
strength, and chemical composition of materials.
0
16. In Sec.  192.227, paragraph (c) is added to read as follows:


Sec.  192.227  Qualification of welders and welding operators.

* * * * *
    (c) Records for transmission pipelines demonstrating each 
individual welder qualification in accordance with this section must be 
retained for the life of the pipeline.
0
17. In Sec.  192.285, paragraph (e) is added to read as follows:


Sec.  192.285  Plastic pipe: Qualifying persons to make joints.

* * * * *
    (e) For transmission pipelines, records demonstrating plastic pipe 
joining qualifications in accordance with this section must be retained 
for the life of the pipeline.
    18. In Sec.  192.319, paragraph (d) is added to read as follows:


Sec.  192.319  Installation of pipe in a ditch.

* * * * *
    (d) Promptly after a ditch for a steel onshore transmission line is 
backfilled, but not later than three months after placing the pipeline 
in service, the operator must perform an assessment to ensure integrity 
of the coating using direct current voltage gradient (DCVG) or 
alternating current voltage gradient (ACVG). The operator must repair 
any coating damage classified as moderate or severe (voltage drop 
greater than 35% for DCVG or 50 dB[mu]v for ACVG) in accordance with 
section 4 of NACE SP0502 (incorporated by reference, see Sec.  192.7) 
within six months of the assessment. Each operator of transmission 
pipelines must make and retain for the life of the pipeline records 
documenting the coating assessment findings and repairs.
0
19. In Sec.  192.452, the introductory text of paragraph (b) is revised 
to read as follows:


Sec.  192.452  How does this subpart apply to converted pipelines and 
regulated onshore gathering lines?

* * * * *
    (b) Regulated onshore gathering lines. For any regulated onshore 
gathering line under Sec.  192.9 existing on [effective date of the 
final rule], that was not previously subject to this part, and for any 
onshore gathering line that becomes a regulated onshore gathering line 
under Sec.  192.9 after April 14, 2006, because of a change in class 
location or increase in dwelling density:
* * * * *
0
20. In Sec.  192.461, paragraph (a)(4) is revised and paragraph (f) is 
added to read as follows:


Sec.  192.461  External corrosion control: Protective coating.

    (a) * * *
    (4) Have sufficient strength to resist damage due to handling 
(including but not limited to transportation, installation, boring, and 
backfilling) and soil stress; and
* * * * *
    (f) Promptly, but no later than three months after backfill of an 
onshore transmission pipeline ditch following repair or replacement (if 
the repair or replacement results in 1,000 feet or more of backfill 
length along the pipeline), conduct surveys to assess any coating 
damage to ensure integrity of the coating using direct current voltage 
gradient (DCVG) or alternating current voltage gradient (ACVG). 
Remediate any coating damage classified as moderate or severe (voltage 
drop greater than 35% for DCVG or 50 dB[mu]v for ACVG) in accordance 
with section 4 of NACE SP0502 (incorporated by reference, see Sec.  
192.7) within six months of the assessment.
0
21. In Sec.  192.465, the section heading and paragraph (d) are revised 
and paragraph (f) is added to read as follows:


Sec.  192.465  External corrosion control: Monitoring and remediation.

* * * * *
    (d) Each operator must promptly correct any deficiencies indicated 
by the inspection and testing provided in paragraphs (a), (b) and (c) 
of this section. Remedial action must be completed promptly, but no 
later than the next monitoring interval in Sec.  192.465 or within one 
year, whichever is less.
* * * * *
    (f) For onshore transmission lines, where any annual test station 
reading (pipe-to-soil potential measurement) indicates cathodic 
protection levels below the required levels in Appendix D of this part, 
the operator must determine the extent of the area with inadequate 
cathodic protection. Close interval surveys must be conducted in both 
directions from the test station with a low cathodic protection (CP) 
reading at a minimum of approximately five foot intervals. Close 
interval surveys must be conducted, where practical based upon 
geographical, technical, or safety reasons. Close interval surveys 
required by this part must be completed with the protective current 
interrupted unless it is impractical to do so for technical or safety 
reasons. Remediation of areas with insufficient cathodic protection 
levels or areas where protective current is found to be leaving the 
pipeline must be performed in accordance with paragraph (d) of this 
section. The operator must confirm restoration of adequate cathodic 
protection by close interval survey over the entire area.
0
22. In Sec.  192.473, paragraph (c) is added to read as follows:


Sec.  192.473  External corrosion control: Interference currents.

* * * * *
    (c) For onshore gas transmission pipelines, the program required by 
paragraph (a) of this section must include:
    (1) Interference surveys for a pipeline system to detect the 
presence and level of any electrical stray current. Interference 
surveys must be taken on a periodic basis including, when there are 
current flow increases over pipeline segment grounding design, from any 
co-located pipelines, structures, or high voltage alternating current 
(HVAC) power lines, including from additional generation, a voltage up 
rating, additional lines, new or enlarged power substations, new 
pipelines or other structures;
    (2) Analysis of the results of the survey to determine the cause of 
the interference and whether the level could impact the effectiveness 
of cathodic protection; and
    (3) Implementation of remedial actions to protect the pipeline 
segment from detrimental interference currents

[[Page 20830]]

promptly but no later than six months after completion of the survey.
0
23. Section 192.478 is added to read as follows:


Sec.  192.478  Internal corrosion control: Onshore transmission 
monitoring and mitigation.

    (a) For onshore transmission pipelines, each operator must develop 
and implement a monitoring and mitigation program to identify 
potentially corrosive constituents in the gas being transported and 
mitigate the corrosive effects. Potentially corrosive constituents 
include but are not limited to: carbon dioxide, hydrogen sulfide, 
sulfur, microbes, and free water, either by itself or in combination. 
Each operator must evaluate the partial pressure of each corrosive 
constituent by itself or in combination to evaluate the effect of the 
corrosive constituents on the internal corrosion of the pipe and 
implement mitigation measures.
    (b) The monitoring and mitigation program in paragraph (a) of this 
section must include:
    (1) At points where gas with potentially corrosive contaminants 
enters the pipeline, the use of gas-quality monitoring equipment to 
determine the gas stream constituents;
    (2) Product sampling, inhibitor injections, in-line cleaning 
pigging, separators or other technology to mitigate the potentially 
corrosive gas stream constituents;
    (3) Evaluation twice each calendar year, at intervals not to exceed 
7\1/2\ months, of gas stream and liquid quality samples and 
implementation of adjustments and mitigative measures to ensure that 
potentially corrosive gas stream constituents are effectively monitored 
and mitigated.
    (c) If corrosive gas is being transported, coupons or other 
suitable means must be used to determine the effectiveness of the steps 
taken to minimize internal corrosion. Each coupon or other means of 
monitoring internal corrosion must be checked at least twice each 
calendar year, at intervals not exceeding 7\1/2\ months.
    (d) Each operator must review its monitoring and mitigation program 
at least twice each calendar year, at intervals not to exceed 7\1/2\ 
months, based on the results of its gas stream sampling and internal 
corrosion monitoring in (a) and (b) and implement adjustments in its 
monitoring for and mitigation of the potential for internal corrosion 
due to the presence of potentially corrosive gas stream constituents.
0
24. In Sec.  192.485, paragraph (c) is revised to read as follows:


Sec.  192.485  Remedial measures: Transmission lines.

* * * * *
    (c) Under paragraphs (a) and (b) of this section, the strength of 
pipe based on actual remaining wall thickness may be determined by the 
procedure in ASME/ANSI B31G (incorporated by reference, see Sec.  
192.7) or the procedure in PRCI PR 3-805 (R-STRENG) (incorporated by 
reference, see Sec.  192.7) for corrosion defects. Both procedures 
apply to corroded regions that do not penetrate the pipe wall over 80 
percent of the wall thickness and are subject to the limitations 
prescribed in the procedures, including the appropriate use of class 
location and pipe longitudinal seam factors in pressure calculations 
for pipe defects. When determining the predicted failure pressure (PFP) 
for gouges, scrapes, selective seam weld corrosion, and crack-related 
defects, appropriate failure criteria must be used and justification of 
the criteria must be documented. Pipe and material properties used in 
remaining strength calculations and the pressure calculations made 
under this paragraph must be documented in reliable, traceable, 
verifiable, and complete records. If such records are not available, 
pipe and material properties used in the remaining strength 
calculations must be based on properties determined and documented in 
accordance with Sec.  192.607.
0
25. Section 192.493 is added to subpart I to read as follows:


Sec.  192.493  In-line inspection of pipelines.

    When conducting in-line inspection of pipelines required by this 
part, each operator must comply with the requirements and 
recommendations of API STD 1163, In-line Inspection Systems 
Qualification Standard; ANSI/ASNT ILI-PQ-2010, In-line Inspection 
Personnel Qualification and Certification; and NACE SP0102-2010, In-
line Inspection of Pipelines (incorporated by reference, see Sec.  
192.7). Assessments may also be conducted using tethered or remotely 
controlled tools, not explicitly discussed in NACE SP0102-2010, 
provided they comply with those sections of NACE SP0102-2010 that are 
applicable.
0
26. In Sec.  192.503, paragraph (a)(1) is revised to read as follows:


Sec.  192.503  General requirements.

    (a) * * *
    (1) It has been tested in accordance with this subpart and Sec.  
192.619, 192.620, or 192.624 to substantiate the maximum allowable 
operating pressure; and
* * * * *
0
27. Section 192.506 is added to read as follows:


Sec.  192.506  Transmission lines: Spike hydrostatic pressure test for 
existing steel pipe with integrity threats.

    (a) Each segment of an existing steel pipeline that is operated at 
a hoop stress level of 30% of specified minimum yield strength or more 
and has been found to have integrity threats that cannot be addressed 
by other means such as in-line inspection or direct assessment must be 
strength tested by a spike hydrostatic pressure test in accordance with 
this section to substantiate the proposed maximum allowable operating 
pressure.
    (b) The spike hydrostatic pressure test must use water as the test 
medium.
    (c) The baseline test pressure without the additional spike test 
pressure is the test pressure specified in Sec.  192.619(a)(2), 
192.620(a)(2), or 192.624, whichever applies.
    (d) The test must be conducted by maintaining the pressure at or 
above the baseline test pressure for at least 8 hours as specified in 
Sec.  192.505(e).
    (e) After the test pressure stabilizes at the baseline pressure and 
within the first two hours of the 8-hour test interval, the hydrostatic 
pressure must be raised (spiked) to a minimum of the lesser of 1.50 
times MAOP or 105% SMYS. This spike hydrostatic pressure test must be 
held for at least 30 minutes.
    (f) If the integrity threat being addressed by the spike test is of 
a time-dependent nature such as a cracking threat, the operator must 
establish an appropriate retest interval and conduct periodic retests 
at that interval using the same spike test pressure. The appropriate 
retest interval and periodic tests for the time-dependent threat must 
be determined in accordance with the methodology in Sec.  192.624(d).
    (g) Alternative technology or alternative technical evaluation 
process. Operators may use alternative technology or an alternative 
technical evaluation process that provides a sound engineering basis 
for establishing a spike hydrostatic pressure test or equivalent. If an 
operator elects to use alternative technology or an alternative 
technical evaluation process, the operator must notify PHMSA at least 
180 days in advance of use in accordance with Sec.  192.624(e). The 
operator must submit the alternative technical evaluation to the 
Associate Administrator of Pipeline Safety with the notification and 
must obtain a ``no objection letter'' from the Associate Administrator 
of Pipeline Safety prior to usage of alternative technology or an 
alternative technical evaluation process.

[[Page 20831]]

The notification must include the following details:
    (1) Descriptions of the technology or technologies to be used for 
all tests, examinations, and assessments;
    (2) Procedures and processes to conduct tests, examinations, and 
assessments, perform evaluations, analyze defects and flaws, and 
remediate defects discovered;
    (3) Data requirements including original design, maintenance and 
operating history, anomaly or flaw characterization;
    (4) Assessment techniques and acceptance criteria;
    (5) Remediation methods for assessment findings;
    (6) Spike hydrostatic pressure test monitoring and acceptance 
procedures, if used;
    (7) Procedures for remaining crack growth analysis and pipe segment 
life analysis for the time interval for additional assessments, as 
required; and
    (8) Evidence of a review of all procedures and assessments by a 
subject matter expert(s) in both metallurgy and fracture mechanics.
0
28. In Sec.  192.517, the introductory text of paragraph (a) is revised 
to read as follows:


Sec.  192.517  Records.

    (a) Each operator must make, and retain for the useful life of the 
pipeline, a record of each test performed under Sec. Sec.  192.505, 
192.506, and 192.507. The record must contain at least the following 
information:
* * * * *
0
29. In Sec.  192.605, paragraph (b)(5) is revised to read as follows:


Sec.  192.605  Procedural manual for operations, maintenance, and 
emergencies.

* * * * *
    (b) * * *
    (5) Operating pipeline controls and systems and operating and 
maintaining pressure relieving or pressure limiting devices, including 
those for starting up and shutting down any part of the pipeline, so 
that the MAOP limit as prescribed by this part cannot be exceeded by 
more than the margin (build-up) allowed for operation of pressure 
relieving devices or pressure-limiting or control devices as specified 
in Sec.  192.201, 192.620(e), 192.731, 192.739, or 192.743, whichever 
applies.
* * * * *
0
30. Section 192.607 is added to read as follows:


Sec.  192.607  Verification of pipeline material: Onshore steel 
transmission pipelines.

    (a) Applicable locations. Each operator must follow the 
requirements of paragraphs (b) through (d) of this section for each 
segment of onshore, steel, gas transmission pipeline installed before 
[effective date of the final rule] that does not have reliable, 
traceable, verifiable, and complete material documentation records for 
line pipe, valves, flanges, and components and meets any of the 
following conditions:
    (1) The pipeline is located in a High Consequence Area as defined 
in Sec.  192.903; or
    (2) The pipeline is located in a class 3 or class 4 location.
    (b) Material documentation plan. Each operator must prepare a 
material documentation plan to implement all actions required by this 
section by [date 180 days after the effective date of the final rule].
    (c) Material documentation. Each operator must have reliable, 
traceable, verifiable, and complete records documenting the following:
    (1) For line pipe and fittings, records must document diameter, 
wall thickness, grade (yield strength and ultimate tensile strength), 
chemical composition, seam type, coating type, and manufacturing 
specification.
    (2) For valves, records must document either the applicable 
standards to which the component was manufactured, the manufacturing 
rating, or the pressure rating. For valves with pipe weld ends, records 
must document the valve material grade and weld end bevel condition to 
ensure compatibility with pipe end conditions;
    (3) For flanges, records must document either the applicable 
standards to which the component was manufactured, the manufacturing 
rating, or the pressure rating, and the material grade and weld end 
bevel condition to ensure compatibility with pipe end conditions;
    (4) For components, records must document the applicable standards 
to which the component was manufactured to ensure pressure rating 
compatibility.
    (d) Verification of material properties. For any material 
documentation records for line pipe, valves, flanges, and components 
specified in paragraph (c) of this section that are not available, the 
operator must take the following actions to determine and verify the 
physical characteristics.
    (1) Develop and implement procedures for conducting non-destructive 
or destructive tests, examinations, and assessments for line pipe at 
all above ground locations.
    (2) Develop and implement procedures for conducting destructive 
tests, examinations, and assessments for buried line pipe at all 
excavations associated with replacements or relocations of pipe 
segments that are removed from service.
    (3) Develop and implement procedures for conducting non-destructive 
or destructive tests, examinations, and assessments for buried line 
pipe at all excavations associated with anomaly direct examinations, in 
situ evaluations, repairs, remediations, maintenance, or any other 
reason for which the pipe segment is exposed, except for segments 
exposed during excavation activities that are in compliance with Sec.  
192.614, until completion of the minimum number of excavations as 
follows:
    (i) The operator must define a separate population of undocumented 
or inadequately documented pipeline segments for each unique 
combination of the following attributes: wall thicknesses (within 10 
percent of the smallest wall thickness in the population), grade, 
manufacturing process, pipe manufacturing dates (within a two year 
interval) and construction dates (within a two year interval).
    (ii) Assessments must be proportionally spaced throughout the 
pipeline segment. Each length of the pipeline segment equal to 10 
percent of the total length must contain 10 percent of the total number 
of required excavations, e.g. a 200 mile population would require 15 
excavations for each 20 miles. For each population defined according to 
paragraph (d)(3)(i) of this section, the minimum number of excavations 
at which line pipe must be tested to verify pipeline material 
properties is the lesser of the following:
    (A) 150 excavations; or
    (B) If the segment is less than 150 miles, a number of excavations 
equal to the population's pipeline mileage (i.e., one set of properties 
per mile), rounded up to the nearest whole number. The mileage for this 
calculation is the cumulative mileage of pipeline segments in the 
population without reliable, traceable, verifiable, and complete 
material documentation.
    (iii) At each excavation, tests for material properties must 
determine diameter, wall thickness, yield strength, ultimate tensile 
strength, Charpy v-notch toughness (where required for failure pressure 
and crack growth analysis), chemical properties, seam type, coating 
type, and must test for the presence of stress corrosion cracking, seam 
cracking, or selective seam weld corrosion using ultrasonic inspection, 
magnetic particle, liquid penetrant, or other appropriate non-
destructive examination techniques. Determination of material property 
values must

[[Page 20832]]

conservatively account for measurement inaccuracy and uncertainty based 
upon comparison with destructive test results using unity charts.
    (iv) If non-destructive tests are performed to determine strength 
or chemical composition, the operator must use methods, tools, 
procedures, and techniques that have been independently validated by 
subject matter experts in metallurgy and fracture mechanics to produce 
results that are accurate within 10% of the actual value with 95% 
confidence for strength values, within 25% of the actual value with 85% 
confidence for carbon percentage and within 20% of the actual value 
with 90% confidence for manganese, chromium, molybdenum, and vanadium 
percentage for the grade of steel being tested.
    (v) The minimum number of test locations at each excavation or 
above-ground location is based on the number of joints of line pipe 
exposed, as follows:
    (A) 10 joints or less: one set of tests for each joint.
    (B) 11 to 100 joints: one set of tests for each five joints, but 
not less than 10 sets of tests.
    (C) Over 100 joints: one set of tests for each 10 joints, but not 
less than 20 sets of tests.
    (vi) For non-destructive tests, at each test location, a set of 
material properties tests must be conducted at a minimum of five places 
in each circumferential quadrant of the pipe for a minimum total of 20 
test readings at each pipe cylinder location.
    (vii) For destructive tests, at each test location, a set of 
materials properties tests must be conducted on each circumferential 
quadrant of a test pipe cylinder removed from each location, for a 
minimum total of four tests at each location.
    (viii) If the results of all tests conducted in accordance with 
paragraphs (d)(3)(i) and (ii) of this section verify that material 
properties are consistent with all available information for each 
population, then no additional excavations are necessary. However, if 
the test results identify line pipe with properties that are not 
consistent with existing expectations based on all available 
information for each population, then the operator must perform tests 
at additional excavations. The minimum number of excavations that must 
be tested depends on the number of inconsistencies observed between as-
found tests and available operator records, in accordance with the 
following table:

------------------------------------------------------------------------
Number of  excavations with  inconsistency
    between test  results and  existing       Minimum number of  total
   expectations  based on all  available      required  excavations for
     information for  each population        population.  The lesser of:
------------------------------------------------------------------------
0.........................................  150 (or pipeline mileage)
1.........................................  225 (or pipeline mileage
                                             times 1.5)
2.........................................  300 (or pipeline mileage
                                             times 2)
>2........................................  350 (or pipeline mileage
                                             times 2.3)
------------------------------------------------------------------------

    (ix) The tests conducted for a single excavation according to the 
requirements of paragraphs (d)(3)(iii) through (vii) of this section 
count as one sample under the sampling requirements of paragraphs 
(d)(3)(i), (ii), and (viii) of this section.
    (4) For mainline pipeline components other than line pipe, the 
operator must develop and implement procedures for establishing and 
documenting the ANSI rating and material grade (to assure compatibility 
with pipe ends).
    (i) Materials in compressor stations, meter stations, regulator 
stations, separators, river crossing headers, mainline valve 
assemblies, operator piping, or cross-connections with isolation valves 
from the mainline pipeline are not required to be tested for chemical 
and mechanical properties.
    (ii) Verification of mainline material properties is required for 
non-line pipe components, including but not limited to, valves, 
flanges, fittings, fabricated assemblies, and other pressure retaining 
components appurtenances that are:
    (A) 2-inch nominal diameter and larger; or
    (B) Material grades greater than 42,000 psi (X-42); or
    (C) Appurtenances of any size that are directly installed on the 
pipeline and cannot be isolated from mainline pipeline pressures.
    (iii) Procedures for establishing material properties for non-line 
pipe components where records are inadequate must be based upon 
documented manufacturing specifications. Where specifications are not 
known, usage of manufacturer's stamped or tagged material pressure 
ratings and material type may be used to establish pressure rating. The 
operator must document the basis of the material properties established 
using such procedures.
    (5) The material properties determined from the destructive or non-
destructive tests required by this section cannot be used to raise the 
original grade or specification of the material, which must be based 
upon the applicable standard referenced in Sec.  192.7.
    (6) If conditions make material verification by the above methods 
impracticable or if the operator chooses to use ``other technology'' or 
``new technology'' (alternative technical evaluation process plan), the 
operator must notify PHMSA at least 180 days in advance of use in 
accordance with paragraph Sec.  192.624(e) of this section. The 
operator must submit the alternative technical evaluation process plan 
to the Associate Administrator of Pipeline Safety with the notification 
and must obtain a ``no objection letter'' from the Associate 
Administrator of Pipeline Safety prior to usage of an alternative 
evaluation process.
0
31. In Sec.  192.613, paragraph (c) is added to read as follows:


Sec.  192.613  Continuing surveillance.

* * * * *
    (c) Following an extreme weather event such as a hurricane or 
flood, an earthquake, landslide, a natural disaster, or other similar 
event that has the likelihood of damage to infrastructure, an operator 
must inspect all potentially affected onshore transmission pipeline 
facilities to detect conditions that could adversely affect the safe 
operation of that pipeline.
    (1) 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 
damage and the need for the additional assessments required under the 
introductory text of paragraph (c) in this section.
    (2) Time period. The inspection required under the introductory 
text of paragraph (c) 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, 
including availability of personnel and equipment, required to perform 
the inspection as determined under paragraph (c)(1) of this section, 
whichever is sooner.
    (3) Remedial action. An operator must take 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 the introductory text of paragraph (c) in this section. Such

[[Page 20833]]

actions might include, but are not limited to:
    (i) Reducing the operating pressure or shutting down the pipeline;
    (ii) Modifying, repairing, or replacing any damaged pipeline 
facilities;
    (iii) Preventing, mitigating, or eliminating any unsafe conditions 
in the pipeline right-of-way;
    (iv) Performing additional patrols, surveys, tests, or inspections;
    (v) Implementing emergency response activities with Federal, State, 
or local personnel; or
    (vi) Notifying affected communities of the steps that can be taken 
to ensure public safety.
0
32. In Sec.  192.619, paragraphs (a)(2) through (4) are revised and 
paragraphs (e) and (f) are added to read as follows:


Sec.  192.619  Maximum allowable operating pressure: Steel or plastic 
pipelines.

    (a) * * *
    (2) The pressure obtained by dividing the pressure to which the 
segment was tested after construction as follows:
    (i) For plastic pipe in all locations, the test pressure is divided 
by a factor of 1.5.
    (ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, 
the test pressure is divided by a factor determined in accordance with 
the following table:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                            Factors \1\, segment--
                                                     ---------------------------------------------------------------------------------------------------
                                                                                Installed after (Nov.
                   Class location                      Installed before (Nov.    11, 1970) and before       Installed after        Converted under Sec.
                                                             12, 1970)          [effective date of the   [effective date of the           192.14
                                                                                     final rule]        final rule minus 1 day]
--------------------------------------------------------------------------------------------------------------------------------------------------------
1...................................................                      1.1                      1.1                     1.25                     1.25
2...................................................                     1.25                     1.25                     1.25                     1.25
3...................................................                      1.4                      1.5                      1.5                      1.5
4...................................................                      1.4                      1.5                      1.5                      1.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ For offshore segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For
  segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters,
  including a pipe riser, the factor is 1.5.

    (3) The highest actual operating pressure to which the segment was 
subjected during the 5 years preceding the applicable date in the 
second column. This pressure restriction applies unless the segment was 
tested according to the requirements in paragraph (a)(2) of this 
section after the applicable date in the third column or the segment 
was uprated according to the requirements in subpart K of this part:

------------------------------------------------------------------------
       Pipeline segment              Pressure date          Test date
------------------------------------------------------------------------
--Onshore gathering line that   March 15, 2006, or      5 years
 first became subject to this    date line becomes       preceding
 part (other than Sec.           subject to this part,   applicable date
 192.612) after April 13, 2006   whichever is later.     in second
 but before [effective date of                           column.
 the final rule].
--Onshore gathering line that   [date one year after
 first became subject to this    effective date of the
 part (other than Sec.           final rule], or date
 192.612) on or after            line becomes subject
 [effective date of the final    to this part,
 rule].                          whichever is later.
--Onshore transmission line     March 15, 2006, or
 that was a gathering line not   date line becomes
 subject to this part before     subject to this part,
 March 15, 2006.                 whichever is later.
Offshore gathering lines......  July 1, 1976..........  July 1, 1971.
All other pipelines...........  July 1, 1970..........  July 1, 1965.
------------------------------------------------------------------------

    (4) The pressure determined by the operator to be the maximum safe 
pressure after considering material records, including material 
properties verified in accordance with Sec.  192.607, and the history 
of the segment, particularly known corrosion and the actual operating 
pressure.
* * * * *
    (e) Notwithstanding the requirements in paragraphs (a) through (d) 
of this section, onshore steel transmission pipelines that meet the 
criteria specified in Sec.  192.624(a) must establish and document the 
maximum allowable operating pressure in accordance with Sec.  192.624 
using one or more of the following:
    (1) Method 1: Pressure Test--Pressure test in accordance with Sec.  
192.624(c)(1)(i) or spike hydrostatic pressure test in accordance with 
Sec.  192.624(c)(1)(ii), as applicable;
    (2) Method 2: Pressure Reduction--Reduction in pipeline maximum 
allowable operating pressure in accordance with Sec.  192.624(c)(2);
    (3) Method 3: Engineering Critical Assessment--Engineering 
assessment and analysis activities in accordance with Sec.  
192.624(c)(3);
    (4) Method 4: Pipe Replacement--Replacement of the pipeline segment 
in accordance with Sec.  192.624(c)(4);
    (5) Method 5: Pressure Reduction for Segments with Small PIR and 
Diameter--Reduction of maximum allowable operating pressure and other 
preventive measures for pipeline segments with small PIRs and 
diameters, in accordance with Sec.  192.624(c)(5); or
    (6) Method 6: Alternative Technology--Alternative procedure in 
accordance with Sec.  192.624(c)(6).
    (f) Operators must maintain all records necessary to establish and 
document the MAOP of each pipeline as long as the pipe or pipeline 
remains in service. Records that establish the pipeline MAOP, include, 
but are not limited to, design, construction, operation, maintenance, 
inspection, testing, material strength, pipe wall thickness, seam type, 
and other related data. Records must be reliable, traceable, 
verifiable, and complete.
0
33. Section 192.624 is added to read as follows:


Sec.  192.624  Maximum allowable operating pressure verification: 
Onshore steel transmission pipelines.

    (a) Applicable locations. The operator of a pipeline segment 
meeting any of the following conditions must establish the maximum 
allowable operating pressure using one or more of the methods specified 
in Sec.  192.624(c)(1) through (6):

[[Page 20834]]

    (1) The pipeline segment has experienced a reportable in-service 
incident, as defined in Sec.  191.3 of this chapter, since its most 
recent successful subpart J pressure test, due to an original 
manufacturing-related defect, a construction-, installation-, or 
fabrication-related defect, or a cracking-related defect, including, 
but not limited to, seam cracking, girth weld cracking, selective seam 
weld corrosion, hard spot, or stress corrosion cracking and the 
pipeline segment is located in one of the following locations:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A class 3 or class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3 if the 
pipe segment can accommodate inspection by means of instrumented inline 
inspection tools (i.e., ``smart pigs'').
    (2) Pressure test records necessary to establish maximum allowable 
operating pressure per subpart J for the pipeline segment, including, 
but not limited to, records required by Sec.  192.517(a), are not 
reliable, traceable, verifiable, and complete and the pipeline is 
located in one of the following locations:
    (i) A high consequence area as defined in Sec.  192.903; or
    (ii) A class 3 or class 4 location
    (3) The pipeline segment maximum allowable operating pressure was 
established in accordance with Sec.  192.619(c) before [effective date 
of the final rule] and is located in one of the following areas:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A class 3 or class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3 if the 
pipe segment can accommodate inspection by means of instrumented inline 
inspection tools (i.e., ``smart pigs'').
    (b) Completion date. For pipelines installed before [effective date 
of the final rule], all actions required by this section must be 
completed according to the following schedule:
    (1) The operator must develop and document a plan for completion of 
all actions required by this section by [date 1 year after effective 
date of the final rule].
    (2) The operator must complete all actions required by this section 
on at least 50% of the mileage of locations that meet the conditions of 
Sec.  192.624(a) by [date 8 years after effective date of the final 
rule].
    (3) The operator must complete all actions required by this section 
on 100% of the mileage of locations that meet the conditions of Sec.  
192.624(a) by [date 15 years after effective date of the final rule].
    (4) If operational and environmental constraints limit the operator 
from meeting the deadlines in Sec.  192.614(b)(2) and (3), the operator 
may petition for an extension of the completion deadlines by up to one 
year, upon submittal of a notification to the Associate Administrator 
of the Office of Pipeline Safety in accordance with paragraph (e) of 
this section. The notification must include an up-to-date plan for 
completing all actions in accordance with paragraph (b)(1) of this 
section, the reason for the requested extension, current status, 
proposed completion date, remediation activities outstanding, and any 
needed temporary safety measures to mitigate the impact on safety.
    (c) Maximum allowable operating pressure determination. The 
operator of a pipeline segment meeting the criteria in paragraph (a) of 
this section must establish its maximum allowable operating pressure 
using one of the following methods:
    (1) Method 1: Pressure test.(i) Perform a pressure test in 
accordance with Sec.  192.505(c). The maximum allowable operating 
pressure will be equal to the test pressure divided by the greater of 
either 1.25 or the applicable class location factor in Sec.  
192.619(a)(2)(ii) or Sec.  192.620(a)(2)(ii).
    (ii) If the pipeline segment includes legacy pipe or was 
constructed using legacy construction techniques or the pipeline has 
experienced an incident, as defined by Sec.  191.3 of this chapter, 
since its most recent successful subpart J pressure test, due to an 
original manufacturing-related defect, a construction-, installation-, 
or fabrication-related defect, or a crack or crack-like defect, 
including, but not limited to, seam cracking, girth weld cracking, 
selective seam weld corrosion, hard spot, or stress corrosion cracking, 
then the operator must perform a spike pressure test in accordance with 
Sec.  192.506. The maximum allowable operating pressure will be equal 
to the test pressure specified in Sec.  192.506(c) divided by the 
greater of 1.25 or the applicable class location factor in Sec.  
192.619(a)(2)(ii) or Sec.  192.620(a)(2)(ii).
    (iii) If the operator has reason to believe any pipeline segment 
may be susceptible to cracks or crack-like defects due to assessment, 
leak, failure, or manufacturing vintage histories, or any other 
available information about the pipeline, the operator must estimate 
the remaining life of the pipeline in accordance with paragraph (d) of 
this section.
    (2) Method 2: Pressure reduction. The pipeline maximum allowable 
operating pressure will be no greater than the highest actual operating 
pressure sustained by the pipeline during the 18 months preceding 
[effective date of the final rule] divided by the greater of 1.25 or 
the applicable class location factor in Sec.  192.619(a)(2)(ii) or 
Sec.  192.620(a)(2)(ii). The highest actual sustained pressure must 
have been reached for a minimum cumulative duration of 8 hours during a 
continuous 30-day period. The value used as the highest actual 
sustained operating pressure must account for differences between 
discharge and upstream pressure on the pipeline by use of either the 
lowest pressure value for the entire segment or using the operating 
pressure gradient (i.e., the location-specific operating pressure at 
each location).
    (i) Where the pipeline segment has had a class location change in 
accordance with Sec.  192.611 and pipe material and pressure test 
records are not available, the operator must reduce the pipeline 
segment MAOP as follows:
    (A) For segments where a class location changed from 1 to 2, from 2 
to 3, or from 3 to 4, reduce the pipeline maximum allowable operating 
pressure to no greater than the highest actual operating pressure 
sustained by the pipeline during the 18 months preceding [effective 
date of the final rule], divided by 1.39 for class 1 to 2, 1.67 for 
class 2 to 3, and 2.00 for class 3 to 4.
    (B) For segments where a class location changed from 1 to 3, reduce 
the pipeline maximum allowable operating pressure to no greater than 
the highest actual operating pressure sustained by the pipeline during 
the 18 months preceding [effective date of the final rule], divided by 
2.00.
    (ii) If the operator has reason to believe any pipeline segment 
contains or may be susceptible to cracks or crack-like defects due to 
assessment, leak, failure, or manufacturing vintage histories, or any 
other available information about the pipeline, the operator must 
estimate the remaining life of the pipeline in accordance with 
paragraph (d) of this section.
    (iii) Future uprating of the segment in accordance with subpart K 
of this part is allowed if the maximum allowable operating pressure is 
established using Method 2 described in paragraph (c)(2) of this 
section.
    (iv) If an operator elects to use Method 2 described in paragraph 
(c)(2) of this section, but desires to use a less conservative pressure 
reduction factor, the operator must notify PHMSA in accordance with 
paragraph (e) of this section no later than seven calendar days after 
establishing the reduced maximum allowable operating pressure.

[[Page 20835]]

The notification must include the following details:
    (A) Descriptions of the operational constraints, special 
circumstances, or other factors that preclude, or make it impractical, 
to use the pressure reduction factor specified in Sec.  192.624(c)(2);
    (B) The fracture mechanics modeling for failure stress pressures 
and cyclic fatigue crack growth analysis that complies with paragraph 
(d) of this section;
    (C) Justification that establishing maximum allowable operating 
pressure by another method allowed by this section is impractical;
    (D) Justification that the reduced maximum allowable operating 
pressure determined by the operator is safe based on analysis of the 
condition of the pipeline segment, including material records, material 
properties verified in accordance Sec.  192.607, and the history of the 
segment, particularly known corrosion and leakage, and the actual 
operating pressure, and additional compensatory preventive and 
mitigative measures taken or planned.
    (E) Planned duration for operating at the requested maximum 
allowable operating pressure, long term remediation measures and 
justification of this operating time interval, including fracture 
mechanics modeling for failure stress pressures and cyclic fatigue 
growth analysis and other validated forms of engineering analysis that 
have been reviewed and confirmed by subject matter experts in 
metallurgy and fracture mechanics.
    (3) Method 3: Engineering critical assessment. Conduct an 
engineering critical assessment and analysis (ECA) to establish the 
material condition of the segment and maximum allowable operating 
pressure. An ECA is an analytical procedure, based on fracture 
mechanics principles, relevant material properties (mechanical and 
fracture resistance properties), operating history, operational 
environment, in-service degradation, possible failure mechanisms, 
initial and final defect sizes, and usage of future operating and 
maintenance procedures to determine the maximum tolerable sizes for 
imperfections. The ECA must assess: threats; loadings and operational 
circumstances relevant to those threats including along the right-of 
way; outcomes of the threat assessment; relevant mechanical and 
fracture properties; in-service degradation or failure processes; 
initial and final defect size relevance. The ECA must quantify the 
coupled effects of any defect in the pipeline.
    (i) ECA analysis. (A) The ECA must integrate and analyze the 
results of the material documentation program required by Sec.  
192.607, if applicable, and the results of all tests, direct 
examinations, destructive tests, and assessments performed in 
accordance with this section, along with other pertinent information 
related to pipeline integrity, including but not limited to close 
interval surveys, coating surveys, and interference surveys required by 
subpart I of this part, root cause analyses of prior incidents, prior 
pressure test leaks and failures, other leaks, pipe inspections, and 
prior integrity assessments, including those required by Sec.  192.710 
and subpart O of this part.
    (B) The ECA must analyze any cracks or crack-like defects remaining 
in the pipe, or that could remain in the pipe, to determine the 
predicted failure pressure (PFP) of each defect. The ECA must use the 
techniques and procedures in 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) (incorporated by reference, see Sec.  192.7) or other 
technically proven methods including but not limited to API RP 579-1/
ASME FFS-1, June 5, 2007, (API 579-1, Second Edition)--Level II or 
Level III, CorLasTM, or PAFFC. The ECA must use conservative 
assumptions for crack dimensions (length and depth) and failure mode 
(ductile, brittle, or both) for the microstructure, location, type of 
defect, and operating conditions (which includes pressure cycling). If 
actual material toughness is not known or not adequately documented by 
reliable, traceable, verifiable, and complete records, then the 
operator must determine a Charpy v-notch toughness based upon the 
material documentation program specified in Sec.  192.607 or use 
conservative values for Charpy v-notch toughness as follows: body 
toughness of less than or equal to 5.0 ft-lb and seam toughness of less 
than or equal to 1 ft-lb.
    (C) The ECA must analyze any metal loss defects not associated with 
a dent including corrosion, gouges, scrapes or other metal loss defects 
that could remain in the pipe to determine the predicted failure 
pressure (PFP). ASME/ANSI B31G (incorporated by reference, see Sec.  
192.7) or AGA Pipeline Research Committee Project PR-3-805 
(``RSTRENG,'' incorporated by reference, see Sec.  192.7) must be used 
for corrosion defects. Both procedures apply to corroded regions that 
do not penetrate the pipe wall over 80 percent of the wall thickness 
and are subject to the limitations prescribed in the equations 
procedures. The ECA must use conservative assumptions for metal loss 
dimensions (length, width, and depth). When determining PFP for gouges, 
scrapes, selective seam weld corrosion, crack-related defects, or any 
defect within a dent, appropriate failure criteria and justification of 
the criteria must be used. If SMYS or actual material yield and 
ultimate tensile strength is not known or not adequately documented by 
reliable, traceable, verifiable, and complete records, then the 
operator must assume grade A pipe or determine the material properties 
based upon the material documentation program specified in Sec.  
192.607.
    (D) The ECA must analyze interacting defects to conservatively 
determine the most limiting PFP for interacting defects. Examples 
include but are not limited to, cracks in or near locations with 
corrosion metal loss, dents with gouges or other metal loss, or cracks 
in or near dents or other deformation damage. The ECA must document all 
evaluations and any assumptions used in the ECA process.
    (E) The maximum allowable operating pressure must be established at 
the lowest PFP for any known or postulated defect, or interacting 
defects, remaining in the pipe divided by the greater of 1.25 or the 
applicable factor listed in Sec.  192.619(a)(2)(ii) or Sec.  
192.620(a)(2)(ii).
    (ii) Use of prior pressure test. If pressure test records as 
described in subpart J of this part and Sec.  192.624(c)(1) exist for 
the segment, then an in-line inspection program is not required, 
provided that the remaining life of the most severe defects that could 
have survived the pressure test have been calculated and a re-
assessment interval has been established. The appropriate retest 
interval and periodic tests for time-dependent threats must be 
determined in accordance with the methodology in Sec.  192.624(d) 
Fracture mechanics modeling for failure stress and crack growth 
analysis.
    (iii) In-line inspection. If the segment does not have records for 
a pressure test in accordance with subpart J of this part and Sec.  
192.624(c)(1), the operator must develop and implement an inline 
inspection (ILI) program using tools that can detect wall loss, 
deformation from

[[Page 20836]]

dents, wrinkle bends, ovalities, expansion, seam defects including 
cracking and selective seam weld corrosion, longitudinal, 
circumferential and girth weld cracks, hard spot cracking, and stress 
corrosion cracking. At a minimum, the operator must conduct an 
assessment using high resolution magnetic flux leakage (MFL) tool, a 
high resolution deformation tool, and either an electromagnetic 
acoustic transducer (EMAT) or ultrasonic testing (UT) tool.
    (A) In lieu of the tools specified in paragraph Sec.  
192.624(c)(3)(i), an operator may use ``other technology'' if it is 
validated by a subject matter expert in metallurgy and fracture 
mechanics to produce an equivalent understanding of the condition of 
the pipe. If an operator elects to use ``other technology,'' it must 
notify the Associate Administrator of Pipeline Safety, at least 180 
days prior to use, in accordance with paragraph (e) of this section and 
receive a ``no objection letter'' from the Associate Administrator of 
Pipeline Safety prior to its usage. The ``other technology'' 
notification must have:
    (1) Descriptions of the technology or technologies to be used for 
all tests, examinations, and assessments including characterization of 
defect size crack assessments (length, depth, and volumetric); and
    (2) Procedures and processes to conduct tests, examinations, and 
assessments, perform evaluations, analyze defects and remediate defects 
discovered.
    (B) If the operator has information that indicates a pipeline 
includes segments that might be susceptible to hard spots based on 
assessment, leak, failure, manufacturing vintage history, or other 
information, then the ILI program must include a tool that can detect 
hard spots.
    (C) If the pipeline has had a reportable incident, as defined in 
Sec.  192.3, attributed to a girth weld failure since its most recent 
pressure test, then the ILI program must include a tool that can detect 
girth weld defects unless the ECA analysis performed in accordance with 
paragraph Sec.  192.624(c)(3)(iii) includes an engineering evaluation 
program to analyze the susceptibility of girth weld failure due to 
lateral stresses.
    (D) Inline inspection must be performed in accordance with Sec.  
192.493.
    (E) All MFL and deformation tools used must have been validated to 
characterize the size of defects within 10% of the actual dimensions 
with 90% confidence. All EMAT or UT tools must have been validated to 
characterize the size of cracks, both length and depth, within 20% of 
the actual dimensions with 80% confidence, with like-similar analysis 
from prior tool runs done to ensure the results are consistent with the 
required corresponding hydrostatic test pressure for the segment being 
evaluated.
    (F) Interpretation and evaluation of assessment results must meet 
the requirements of Sec. Sec.  192.710, 192.713, and subpart O of this 
part, and must conservatively account for the accuracy and reliability 
of ILI, in-the-ditch examination methods and tools, and any other 
assessment and examination results used to determine the actual sizes 
of cracks, metal loss, deformation and other defect dimensions by 
applying the most conservative limit of the tool tolerance 
specification. ILI and in-the-ditch examination tools and procedures 
for crack assessments (length, depth, and volumetric) must have 
performance and evaluation standards confirmed for accuracy through 
confirmation tests for the type defects and pipe material vintage being 
evaluated. Inaccuracies must be accounted for in the procedures for 
evaluations and fracture mechanics models for predicted failure 
pressure determinations.
    (G) Anomalies detected by ILI assessments must be repaired in 
accordance with applicable repair criteria in Sec. Sec.  192.713 and 
192.933.
    (iv) If the operator has reason to believe any pipeline segment 
contains or may be susceptible to cracks or crack-like defects due to 
assessment, leak, failure, or manufacturing vintage histories, or any 
other available information about the pipeline, the operator must 
estimate the remaining life of the pipeline in accordance with 
paragraph Sec.  192.624(d).
    (4) Method 4: Pipe replacement. Replace the pipeline segment.
    (5) Method 5: Pressure reduction for segments with small potential 
impact radius and diameter. Pipelines with a maximum allowable 
operating pressure less than 30 percent of specified minimum yield 
strength, a potential impact radius (PIR) less than or equal to 150 
feet, nominal diameter equal to or less than 8-inches, and which cannot 
be assessed using inline inspection or pressure test, may establish the 
maximum allowable operating pressure as follows:
    (i) Reduce the pipeline maximum allowable operating pressure to no 
greater than the highest actual operating pressure sustained by the 
pipeline during 18 months preceding [effective date of the final rule], 
divided by 1.1. The highest actual sustained pressure must have been 
reached for a minimum cumulative duration of eight hours during one 
continuous 30-day period. The reduced maximum allowable operating 
pressure must account for differences between discharge and upstream 
pressure on the pipeline by use of either the lowest value for the 
entire segment or the operating pressure gradient (i.e., the location 
specific operating pressure at each location);
    (ii) Conduct external corrosion direct assessment in accordance 
with Sec.  192.925, and internal corrosion direct assessment in 
accordance with Sec.  192.927;
    (iii) Develop and implement procedures for conducting non-
destructive tests, examinations, and assessments for cracks and crack-
like defects, including but not limited to stress corrosion cracking, 
selective seam weld corrosion, girth weld cracks, and seam defects, for 
pipe at all excavations associated with anomaly direct examinations, in 
situ evaluations, repairs, remediations, maintenance, or any other 
reason for which the pipe segment is exposed, except for segments 
exposed during excavation activities that are in compliance with Sec.  
192.614;
    (iv) Conduct monthly patrols in Class 1 and 2 locations, at an 
interval not to exceed 45 days; weekly patrols in Class 3 locations not 
to exceed 10 days; and semi-weekly patrols in Class 4 locations, at an 
interval not to exceed six days, in accordance with Sec.  192.705;
    (v) Conduct monthly, instrumented leakage surveys in Class 1 and 2 
locations, at intervals not to exceed 45 days; weekly leakage surveys 
in Class 3 locations at intervals not to exceed 10 days; and semi-
weekly leakage surveys in Class 4 locations, at intervals not to exceed 
six days, in accordance with Sec.  192.706; and
    (vi) Odorize gas transported in the segment, in accordance with 
Sec.  192.625;
    (vii) If the operator has reason to believe any pipeline segment 
contains or may be susceptible to cracks or crack-like defects due to 
assessment, leak, failure, or manufacturing vintage histories, or any 
other available information about the pipeline, the operator must 
estimate the remaining life of the pipeline in accordance with 
paragraph Sec.  192.624(d).
    (viii) Under Method 5 described in paragraph (c)(5) of this 
section, future uprating of the segment in accordance with subpart K of 
this part is allowed.
    (6) Method 6: Alternative technology. Operators may use an 
alternative technical evaluation process that provides a sound 
engineering basis for establishing maximum allowable operating 
pressure. If an operator elects to use alternative technology, the

[[Page 20837]]

operator must notify PHMSA at least 180 days in advance of use in 
accordance with paragraph (e) of this section. The operator must submit 
the alternative technical evaluation to PHMSA with the notification and 
obtain a ``no objection letter'' from the Associate Administrator of 
Pipeline Safety prior to usage of alternative technology. The 
notification must include the following details:
    (i) Descriptions of the technology or technologies to be used for 
tests, examinations, and assessments, establishment of material 
properties, and analytical techniques, with like-similar analysis from 
prior tool runs done to ensure the results are consistent with the 
required corresponding hydrostatic test pressure for the segment being 
evaluated.
    (ii) Procedures and processes to conduct tests, examinations, and 
assessments, perform evaluations, analyze defects and flaws, and 
remediate defects discovered;
    (iii) Methodology and criteria used to determine reassessment 
period or need for a reassessment including references to applicable 
regulations from this part and industry standards;
    (iv) Data requirements including original design, maintenance and 
operating history, anomaly or flaw characterization;
    (v) Assessment techniques and acceptance criteria, including 
anomaly detection confidence level, probability of detection, and 
uncertainty of PFP quantified as a fraction of specified minimum yield 
strength;
    (vi) If the operator has reason to believe any pipeline segment 
contains or may be susceptible to cracks or crack-like defects due to 
assessment, leak, failure, or manufacturing vintage histories, or any 
other available information about the pipeline, the operator must 
estimate the remaining life of the pipeline in accordance with 
paragraph (d) of this section;
    (vii) Remediation methods with proven technical practice;
    (viii) Schedules for assessments and remediation;
    (ix) Operational monitoring procedures;
    (x) Methodology and criteria used to justify and establish the 
maximum allowable operating pressure; and
    (xi) Documentation requirements for the operator's process, 
including records to be generated.
    (d) Fracture mechanics modeling for failure stress and crack growth 
analysis. (1) If the operator has reason to believe any pipeline 
segment contains or may be susceptible to cracks or crack-like defects 
due to assessment, leak, failure, or manufacturing vintage histories, 
or any other available information about the pipeline, the operator 
must perform fracture mechanics modeling for failure stress pressure 
and crack growth analysis to determine the remaining life of the 
pipeline at the maximum allowable operating pressure based on the 
applicable test pressures in accordance with Sec.  192.506 including 
the remaining crack flaw size in the pipeline segment, any pipe failure 
or leak mechanisms identified during pressure testing, pipe 
characteristics, material toughness, failure mechanism for the 
microstructure(ductile and brittle or both), location and type of 
defect, operating environment, and operating conditions including 
pressure cycling. Fatigue analysis must be performed using a recognized 
form of the Paris Law as specified in Battelle's Final Report No. 13-
021; Subtask 2.5 (incorporated by reference, see Sec.  192.7) or other 
technically appropriate engineering methodology validated by a subject 
matter expert in metallurgy and fracture mechanics to give conservative 
predictions of flaw growth and remaining life. When assessing other 
degradation processes, the analysis must be performed using recognized 
rate equations whose applicability and validity is demonstrated for the 
case being evaluated. For cases involving calculation of the critical 
flaw size, conservative remaining life analysis must assess the 
smallest critical sizes and use a lower-bound toughness. For cases 
dealing with an estimating of the defect sizes that would survive a 
hydro test pressure, conservative remaining life analysis that must 
assess the largest surviving sizes and use upper-bound values of 
material strength and toughness. The analysis must include a 
sensitivity analysis to determine conservative estimates of time to 
failure for cracks. Material strength and toughness values used must 
reflect the local conditions for growth, and use data that is case 
specific to estimate the range of strength and toughness for such 
analysis. When the strength and toughness and limits on their ranges 
are unknown, the analysis must assume material strength and fracture 
toughness levels corresponding to the type of assessment being 
performed, as follows:
    (i) For an assessment using a hydrostatic pressure test use a full 
size equivalent Charpy upper-shelf energy level of 120 ft-lb and a flow 
stress equal to the minimum specified ultimate tensile strength of the 
base pipe material. The purpose of using the high level of Charpy 
energy and flow stress (equal to the ultimate tensile strength) is for 
an operator to calculate the largest defects that could have survived a 
given level of hydrostatic test. The resulting maximum-size defects 
lead to the shortened predicted times to failure,
    (ii) For ILI assessments unless actual ranges of values of strength 
and toughness are known, the analysis must use the specified minimum 
yield strength and the specified minimum ultimate tensile strength and 
Charpy toughness valves lower than or equal to: 5.0 ft-lb for body 
cracks; 1.0 ft-lb for ERW seam bond line defects such as cold weld, 
lack of fusion, and selective seam weld corrosion defects.
    (iii) The sensitivity analysis to determine the time to failure for 
a crack must include operating history, pressure tests, pipe geometry, 
wall thickness, strength level, flow stress, and operating environment 
for the pipe segment being assessed, including at a minimum the role of 
the pressure-cycle spectrum.
    (2) If actual material toughness is not known or not adequately 
documented for fracture mechanics modeling for failure stress pressure, 
the operator must use a conservative Charpy energy value to determine 
the toughness based upon the material documentation program specified 
in Sec.  192.607; or use maximum Charpy energy values of 5.0 ft-lb for 
body cracks; 1.0 ft-lb for cold weld, lack of fusion, and selective 
seam weld corrosion defects as documented in Battelle Final Reports 
(``Battelle's Experience with ERW and Flash Weld Seam Failures: Causes 
and Implications''--Task 1.4), 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) (incorporated by reference, see Sec.  192.7); or other 
appropriate technology or technical publications that an operator 
demonstrates can provide a conservative Charpy energy values of the 
crack-related conditions of the line pipe.
    (3) The analysis must account for metallurgical properties at the 
location being analyzed (such as in the properties of the parent pipe, 
weld heat affected zone, or weld metal bond line), and must account for 
the likely failure mode of anomalies (such as brittle fracture, ductile 
fracture or both). If the likely failure mode is uncertain or unknown, 
the analysis must analyze both failure modes and use the more 
conservative result. Appropriate fracture

[[Page 20838]]

mechanics modeling for failure stress pressures in the brittle failure 
mode is the Raju/Newman Model (Task 4.5) and for the ductile failure 
mode is the Modified LnSec (Task 4.5) and Raju/Newman Models or other 
proven-equivalent engineering fracture mechanics models for determining 
conservative failure pressures may be used.
    (4) If the predicted remaining life of the pipeline calculated by 
this analysis is 5 years or less, then the operator must perform a 
pressure test in accordance with paragraph (c)(1) of this section or 
reduce the maximum allowable operating pressure of the pipeline in 
accordance with paragraph (c)(2) of this section to establish the 
maximum allowable operating pressure within 1-year of analysis;
    (5) The operator must re-evaluate the remaining life of the 
pipeline before 50% of the remaining life calculated by this analysis 
has expired, but within 15 years. The operator must determine and 
document if further pressure tests or use of other methods are required 
at that time. The operator must continue to re-evaluate the remaining 
life of the pipeline before 50% of the remaining life calculated in the 
most recent evaluation has expired. If the analysis results show that a 
50% remaining life reduction does not give a sufficient safety factor 
based upon technical evaluations then a more conservative remaining 
life safety factor must be used.
    (6) The analysis required by this paragraph (d) of this section 
must be reviewed and confirmed by a subject matter expert in both 
metallurgy and fracture mechanics.
    (e) Notifications. An operator must submit all notifications 
required by this section to the Associate Administrator for Pipeline 
Safety, by:
    (1) Sending the notification to the Office of Pipeline Safety, 
Pipeline and Hazardous Material Safety Administration, U.S. Department 
of Transportation, Information Resources Manager, PHP-10, 1200 New 
Jersey Avenue SE., Washington, DC 20590-0001;
    (2) Sending the notification to the Information Resources Manager 
by facsimile to (202) 366-7128; or
    (3) Sending the notification to the Information Resources Manager 
by email to InformationResourcesManager@dot.gov.
    (4) An operator must also send a copy to a State pipeline safety 
authority when the pipeline is located in a State where PHMSA has an 
interstate agent agreement, or an intrastate pipeline is regulated by 
that State.
    (f) Records. Each operator must keep for the life of the pipeline 
reliable, traceable, verifiable, and complete records of the 
investigations, tests, analyses, assessments, repairs, replacements, 
alterations, and other actions made in accordance with the requirements 
of this section.
0
34. Section 192.710 is added to read as follows:


Sec.  192.710  Pipeline assessments.

    (a) Applicability. (1) This section applies to onshore transmission 
pipeline segments that are located in:
    (i) A class 3 or class 4 location; or
    (ii) A moderate consequence area as defined in Sec.  192.3 if the 
pipe segment can accommodate inspection by means of instrumented inline 
inspection tools (i.e., ``smart pigs'').
    (2) This section does not apply to a pipeline segment located in a 
high consequence area as defined in Sec.  192.903.
    (b) General. (1) An operator must perform initial assessments in 
accordance with this section no later than [date 15 years after 
effective date of the final rule] and periodic reassessments every 20 
years thereafter, or a shorter reassessment internal based upon the 
type anomaly, operational, material, and environmental conditions found 
on the pipeline segment, or as otherwise necessary to ensure public 
safety.
    (2) Prior assessment. An operator may use a prior assessment 
conducted before [effective date of the final rule] as an initial 
assessment for the segment, if the assessment meets the subpart O of 
this part requirements for in-line inspection. If an operator uses this 
prior assessment as its initial assessment, the operator must reassess 
the pipeline segment according to the reassessment interval specified 
in paragraph (b)(1) of this section.
    (3) MAOP verification. An operator may use an integrity assessment 
to meet the requirements of this section if the pipeline segment 
assessment is conducted in accordance with the integrity assessment 
requirements of Sec.  192.624(c) for establishing MAOP.
    (c) Assessment method. The initial assessments and the 
reassessments required by paragraph (b) of this section must be capable 
of identifying anomalies and defects associated with each of the 
threats to which the pipeline is susceptible and must be performed 
using one or more of the following methods:
    (1) Internal inspection tool or tools capable of detecting 
corrosion, deformation and mechanical damage (including dents, gouges 
and grooves), material cracking and crack-like defects (including 
stress corrosion cracking, selective seam weld corrosion, 
environmentally assisted cracking, and girth weld cracks), hard spots, 
and any other threats to which the segment is susceptible. When 
performing an assessment using an in-line inspection tool, an operator 
must comply with Sec.  192.493;
    (2) Pressure test conducted in accordance with subpart J of this 
part. The use of pressure testing is appropriate for threats such as 
internal corrosion, external corrosion, and other environmentally 
assisted corrosion mechanisms, manufacturing and related defect 
threats, including defective pipe and pipe seams, dents and other forms 
of mechanical damage;
    (3) ``Spike'' hydrostatic pressure test in accordance with Sec.  
192.506;
    (4) Excavation and in situ direct examination by means of visual 
examination and direct measurement and recorded non-destructive 
examination results and data needed to assess all threats, including 
but not limited to, ultrasonic testing (UT), radiography, and magnetic 
particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in appendix 
F;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. Use of direct 
assessment is allowed only if the line is not capable of inspection by 
internal inspection tools and is not practical to assess (due to low 
operating pressures and flows, lack of inspection technology, and 
critical delivery areas such as hospitals and nursing homes) using the 
methods specified in paragraphs (d)(1) through (5) of this section. An 
operator must conduct the direct assessment in accordance with the 
requirements listed in Sec.  192.923 and with the applicable 
requirements specified in Sec. Sec.  192.925, 192.927 or 192.929; or
    (7) Other technology or technologies that an operator demonstrates 
can provide an equivalent understanding of the line pipe for each of 
the threats to which the pipeline is susceptible.
    (8) For segments with MAOP less than 30% of the SMYS, an operator 
must assess for the threats of external and internal corrosion, as 
follows:
    (i) External corrosion. An operator must take one of the following 
actions to address external corrosion on a low stress segment:
    (A) Cathodically protected pipe. To address the threat of external 
corrosion on cathodically protected pipe, an operator must perform an 
indirect assessment (i.e. indirect examination

[[Page 20839]]

tool/method such as close interval survey, alternating current voltage 
gradient, direct current voltage gradient, or equivalent) at least 
every seven years on the segment. An operator must use the results of 
each survey as part of an overall evaluation of the cathodic protection 
and corrosion threat for the segment. This evaluation must consider, at 
minimum, the leak repair and inspection records, corrosion monitoring 
records, exposed pipe inspection records, and the pipeline environment.
    (B) Unprotected pipe or cathodically protected pipe where indirect 
assessments are impractical. To address the threat of external 
corrosion on unprotected pipe or cathodically protected pipe where 
indirect assessments are impractical, an operator must--
    (1) Conduct leakage surveys as required by Sec.  192.706 at 4-month 
intervals; and
    (2) Every 18 months, identify and remediate areas of active 
corrosion by evaluating leak repair and inspection records, corrosion 
monitoring records, exposed pipe inspection records, and the pipeline 
environment.
    (ii) Internal corrosion. To address the threat of internal 
corrosion on a low stress segment, an operator must--
    (A) Conduct a gas analysis for corrosive agents at least twice each 
calendar year;
    (B) Conduct periodic testing of fluids removed from the segment. At 
least once each calendar year test the fluids removed from each storage 
field that may affect a segment; and
    (C) At least every seven (7) years, integrate data from the 
analysis and testing required by paragraphs (c)(8)(ii)(A) and (B) of 
this section with applicable internal corrosion leak records, incident 
reports, safety-related condition reports, repair records, patrol 
records, exposed pipe reports, and test records, and define and 
implement appropriate remediation actions.
    (d) 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. In addition, an 
operator must explicitly consider uncertainties in reported results 
(including, but not limited to, tool tolerance, detection threshold, 
probability of detection, probability of identification, sizing 
accuracy, conservative anomaly interaction criteria, location accuracy, 
anomaly findings, and unity chart plots or equivalent for determining 
uncertainties and verifying tool performance) in identifying and 
characterizing anomalies.
    (e) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information to determine that a condition exists. 
An operator must promptly, but no later than 180 days after an 
assessment, obtain sufficient information about a condition to make the 
determination required under paragraph (d), unless the operator can 
demonstrate that that 180-days is impracticable.
    (f) Remediation. An operator must comply with the requirements in 
Sec.  192.713 if a condition that could adversely affect the safe 
operation of a pipeline is discovered.
    (g) Consideration of information. An operator must consider all 
available information about a pipeline in complying with the 
requirements in paragraphs (a) through (f) of this section.
0
35. In Sec.  192.711, paragraph (b)(1) is revised to read as follows:


Sec.  192.711  Transmission lines: General requirements for repair 
procedures.

* * * * *
    (b) * * *
    (1) Non integrity management repairs. Whenever an operator 
discovers any condition that could adversely affect the safe operation 
of a pipeline segment not covered under subpart O of this part, Gas 
Transmission Pipeline Integrity Management, it must correct the 
condition as prescribed in Sec.  192.713. However, if the condition is 
of such a nature that it presents an immediate hazard to persons or 
property, the operator must reduce the operating pressure to a level 
not exceeding 80% of the operating pressure at the time the condition 
was discovered and take additional immediate temporary measures in 
accordance with paragraph (a) of this section to protect persons or 
property. The operator must make permanent repairs as soon as feasible.
* * * * *
0
36. Section 192.713 is revised to read as follows:


Sec.  192.713  Transmission lines: Permanent field repair of 
imperfections and damages.

    (a) This section applies to transmission lines. Line segments that 
are located in high consequence areas, as defined in Sec.  192.903, 
must also comply with applicable actions specified by the integrity 
management requirements in subpart O of this part.
    (b) General. Each operator must, in repairing its pipeline systems, 
ensure that the repairs are made in a safe manner and are made so as to 
prevent damage to persons, property, or the environment. Operating 
pressure must be at a safe level during repair operations.
    (c) Repair. Each imperfection or damage that impairs the 
serviceability of pipe in a steel transmission line operating at or 
above 40 percent of SMYS must be--
    (1) Removed by cutting out and replacing a cylindrical piece of 
pipe; or
    (2) Repaired by a method that reliable engineering tests and 
analyses show can permanently restore the serviceability of the pipe.
    (d) Remediation schedule. For pipelines not located in high 
consequence areas, an operator must complete the remediation of a 
condition according to the following schedule:
    (1) Immediate repair conditions. An operator must repair the 
following conditions immediately upon discovery:
    (i) A calculation of the remaining strength of the pipe shows a 
predicted failure pressure less than or equal to 1.1 times the maximum 
allowable operating pressure at the location of the anomaly. Suitable 
remaining strength calculation methods include, ASME/ANSI B31G; 
RSTRENG; or an alternative equivalent method of remaining strength 
calculation. These documents are incorporated by reference and 
available at the addresses listed in Sec.  192.7(c). Pipe and material 
properties used in remaining strength calculations must be documented 
in reliable, traceable, verifiable, and complete records. If such 
records are not available, pipe and material properties used in the 
remaining strength calculations must be based on properties determined 
and documented in accordance with Sec.  192.607.
    (ii) A dent that has any indication of metal loss, cracking or a 
stress riser.
    (iii) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (iv) An indication of metal-loss affecting a detected longitudinal 
seam, if that seam was formed by direct current or low-frequency or 
high frequency electric resistance welding or by electric flash 
welding.
    (v) Any indication of significant stress corrosion cracking (SCC).
    (vi) Any indication of significant selective seam weld corrosion 
(SSWC).
    (vii) An indication or anomaly that in the judgment of the person 
designated by the operator to evaluate the assessment results requires 
immediate action.
    (2) Until the remediation of a condition specified in paragraph 
(d)(1) of this section is complete, an operator must reduce the 
operating pressure of the affected pipeline to the lower of:

[[Page 20840]]

    (i) A level that restores the safety margin commensurate with the 
design factor for the Class Location in which the affected pipeline is 
located, determined using ASME/ANSI B31G (``Manual for Determining the 
Remaining Strength of Corroded Pipelines'' (1991) or AGA Pipeline 
Research Committee Project PR-3-805 (``A Modified Criterion for 
Evaluating the Remaining Strength of Corroded Pipe'' (December 1989)) 
(``RSTRENG,'' incorporated by reference, see Sec.  192.7) for corrosion 
defects. Both procedures apply to corroded regions that do not 
penetrate the pipe wall over 80 percent of the wall thickness and are 
subject to the limitations prescribed in the equations procedures. When 
determining the predicted failure pressure (PFP) for gouges, scrapes, 
selective seam weld corrosion, crack-related defects, appropriate 
failure criteria and justification of the criteria must be used. If 
SMYS or actual material yield and ultimate tensile strength is not 
known or not adequately documented by reliable, traceable, verifiable, 
and complete records, then the operator must assume grade A pipe or 
determine the material properties based upon the material documentation 
program specified in Sec.  192.607; or
    (ii) 80% of pressure at the time of discovery, whichever is lower.
    (3) Two-year conditions. An operator must repair the following 
conditions within two years of discovery:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper 2/3 of the pipe) with a depth greater than 6% of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than nominal pipe size (NPS) 12).
    (ii) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or at a longitudinal or helical 
(spiral) seam weld.
    (iii) A calculation of the remaining strength of the pipe shows a 
predicted failure pressure ratio (FPR) at the location of the anomaly 
less than or equal to 1.25 for Class 1 locations, 1.39 for Class 2 
locations, 1.67 for Class 3 locations, and 2.00 for Class 4 locations. 
This calculation must adequately account for the uncertainty associated 
with the accuracy of the tool used to perform the assessment.
    (iv) An area of corrosion with a predicted metal loss greater than 
50% of nominal wall.
    (v) Predicted metal loss greater than 50% of nominal wall that is 
located at a crossing of another pipeline, or is in an area with 
widespread circumferential corrosion, or is in an area that could 
affect a girth weld.
    (vi) A gouge or groove greater than 12.5% of nominal wall.
    (vii) Any indication of crack or crack-like defect other than an 
immediate condition.
    (4) Monitored conditions. An operator does not have to schedule the 
following conditions for remediation, but must record and monitor the 
conditions during subsequent risk assessments and integrity assessments 
for any change that may require remediation:
    (i) A dent with a depth greater than 6% of the pipeline diameter 
(greater than 0.50 inches in depth for a pipeline diameter less than 
NPS 12) located between the 4 o'clock position and the 8 o'clock 
position (bottom 1/3 of the pipe).
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper 2/3 of the pipe) with a depth greater than 6% of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter 
less than nominal pipe size (NPS) 12), and engineering analyses of the 
dent demonstrate critical strain levels are not exceeded.
    (e) Other conditions. Unless another timeframe is specified in 
paragraph (d) of this section, an operator must take appropriate 
remedial action to correct any condition that could adversely affect 
the safe operation of a pipeline system in accordance with the 
criteria, schedules and methods defined in the operator's Operating and 
Maintenance procedures.
    (f) In situ direct examination of crack defects. Whenever required 
by this part, operators must perform direct examination of known 
locations of cracks or crack-like defects using inverse wave field 
extrapolation (IWEX), phased array, automated ultrasonic testing (AUT), 
or equivalent technology that has been validated to detect tight cracks 
(equal to or less than 0.008 inches). In-the-ditch examination tools 
and procedures for crack assessments (length, depth, and volumetric) 
must have performance and evaluation standards, including pipe or weld 
surface cleanliness standards for the inspection, confirmed by subject 
matter experts qualified by knowledge, training, and experience in 
direct examination inspection and in metallurgy and fracture mechanics 
for accuracy for the type of defects and pipe material being evaluated. 
The procedures must account for inaccuracies in evaluations and 
fracture mechanics models for failure pressure determinations.
0
37. Section 192.750 is added to read as follows:


Sec.  192.750  Launcher and receiver safety.

    Any launcher or receiver used after [date 6 months after effective 
date of the final rule], must be equipped with a device capable of 
safely relieving pressure in the barrel before removal or opening of 
the launcher or receiver barrel closure or flange and insertion or 
removal of in-line inspection tools, scrapers, or spheres. The operator 
must use a suitable device to indicate that pressure has been relieved 
in the barrel or must provide a means to prevent opening of the barrel 
closure or flange, or prevent insertion or removal of in-line 
inspection tools, scrapers, or spheres, if pressure has not been 
relieved.
0
38. In Sec.  192.911, paragraph (k) is revised to read as follows:


Sec.  192.911  What are the elements of an integrity management 
program?

* * * * *
    (k) A management of change process as required by Sec.  192.13(d).
* * * * *
0
39. In Sec.  192.917, paragraphs (a), (b), (c), (d), (e)(2), (e)(3), 
and (e)(4) are revised to read as follows:


Sec.  192.917  How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    (a) Threat identification. An operator must identify and evaluate 
all potential threats to each covered pipeline segment. Potential 
threats that an operator must consider include, but are not limited to, 
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see 
Sec.  192.7), section 2, which are grouped under the following four 
threats:
    (1) Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    (2) Stable threats, such as manufacturing, welding/fabrication, or 
equipment defects;
    (3) Time independent threats such as third party/mechanical damage, 
incorrect operational procedure, weather related and outside force, 
including consideration of seismicity, geology, and soil stability of 
the area; and
    (4) Human error such as operational mishaps and design and 
construction mistakes.
    (b) Data gathering and integration. To identify and evaluate the 
potential threats to a covered pipeline segment, an operator must 
gather, verify, validate, and integrate existing data and

[[Page 20841]]

information on the entire pipeline that could be relevant to the 
covered segment. In performing data gathering and integration, an 
operator must follow the requirements in ASME/ANSI B31.8S, section 4. 
At a minimum, an operator must gather and evaluate the set of data 
specified in paragraph (b)(1) of this section and appendix A to ASME/
ANSI B31.8S. The evaluation must analyze both the covered segment and 
similar non-covered segments, and must:
    (1) Integrate information about pipeline attributes and other 
relevant information, including, but not limited to:
    (i) Pipe diameter, wall thickness, grade, seam type and joint 
factor;
    (ii) Manufacturer and manufacturing date, including manufacturing 
data and records;
    (iii) Material properties including, but not limited to, diameter, 
wall thickness, grade, seam type, hardness, toughness, hard spots, and 
chemical composition;
    (iv) Equipment properties;
    (v) Year of installation;
    (vi) Bending method;
    (vii) Joining method, including process and inspection results;
    (viii) Depth of cover surveys including stream and river crossings, 
navigable waterways, and beach approaches;
    (ix) Crossings, casings (including if shorted), and locations of 
foreign line crossings and nearby high voltage power lines;
    (x) Hydrostatic or other pressure test history, including test 
pressures and test leaks or failures, failure causes, and repairs;
    (xi) Pipe coating methods (both manufactured and field applied) 
including method or process used to apply girth weld coating, 
inspection reports, and coating repairs;
    (xii) Soil, backfill;
    (xiii) Construction inspection reports, including but not limited 
to:
    (A) Girth weld non-destructive examinations;
    (B) Post backfill coating surveys;
    (C) Coating inspection (``jeeping'') reports;
    (xiv) Cathodic protection installed, including but not limited to 
type and location;
    (xv) Coating type;
    (xvi) Gas quality;
    (xvii) Flow rate;
    (xviii) Normal maximum and minimum operating pressures, including 
maximum allowable operating pressure (MAOP);
    (xix) Class location;
    (xx) Leak and failure history including any in-service ruptures or 
leaks from incident reports, abnormal operations, safety related 
conditions (both reported and unreported) and failure investigations 
required by Sec.  192.617, and their identified causes and 
consequences;
    (xxi) Coating condition;
    (xxii) CP system performance;
    (xxiii) Pipe wall temperature;
    (xxiv) Pipe operational and maintenance inspection reports, 
including but not limited to:
    (A) Data gathered through integrity assessments required under this 
part, including but not limited to in-line inspections, pressure tests, 
direct assessment, guided wave ultrasonic testing, or other methods;
    (B) Close interval survey (CIS) and electrical survey results;
    (C) Cathodic protection (CP) rectifier readings;
    (D) CP test point survey readings and locations;
    (E) AC/DC and foreign structure interference surveys;
    (F) Pipe coating surveys, including surveys to detect coating 
damage, disbonded coatings, or other conditions that compromise the 
effectiveness of corrosion protection, including but not limited to 
direct current voltage gradient or alternating current voltage gradient 
inspections;
    (G) Results of examinations of exposed portions of buried pipelines 
(e.g., pipe and pipe coating condition, see Sec.  192.459), including 
the results of any non-destructive examinations of the pipe, seam or 
girth weld, i.e. bell hole inspections;
    (H) Stress corrosion cracking (SCC) excavations and findings;
    (I) Selective seam weld corrosion (SSWC) excavations and findings;
    (J) Gas stream sampling and internal corrosion monitoring results, 
including cleaning pig sampling results;
    (xxv) Outer Diameter/Inner Diameter corrosion monitoring;
    (xxvi) Operating pressure history and pressure fluctuations, 
including analysis of effects of pressure cycling and instances of 
exceeding MAOP by any amount;
    (xxvii) Performance of regulators, relief valves, pressure control 
devices, or any other device to control or limit operating pressure to 
less than MAOP;
    (xxviii) Encroachments and right-of-way activity, including but not 
limited to, one-call data, pipe exposures resulting from encroachments, 
and excavation activities due to development or planned development 
along the pipeline;
    (xxix) Repairs;
    (xxx) Vandalism;
    (xxxi) External forces;
    (xxxii) Audits and reviews;
    (xxxiii) Industry experience for incident, leak and failure 
history;
    (xxxiv) Aerial photography;
    (xxxv) Exposure to natural forces in the area of the pipeline, 
including seismicity, geology, and soil stability of the area; and
    (xxxvi) Other pertinent information derived from operations and 
maintenance activities and any additional tests, inspections, surveys, 
patrols, or monitoring required under this part.
    (2) Use objective, traceable, verified, and validated information 
and data as inputs, to the maximum extent practicable. If input is 
obtained from subject matter experts (SMEs), the operator must employ 
measures to adequately correct any bias in SME input. Bias control 
measures may include training of SMEs and use of outside technical 
experts (independent expert reviews) to assess quality of processes and 
the judgment of SMEs. Operator must document the names of all SMEs and 
information submitted by the SMEs for the life of the pipeline.
    (3) Identify and analyze spatial relationships among anomalous 
information (e.g., corrosion coincident with foreign line crossings; 
evidence of pipeline damage where overhead imaging shows evidence of 
encroachment). Storing or recording the information in a common 
location, including a geographic information system (GIS), alone, is 
not sufficient; and
    (4) Analyze the data for interrelationships among pipeline 
integrity threats, including combinations of applicable risk factors 
that increase the likelihood of incidents or increase the potential 
consequences of incidents.
    (c) Risk assessment. An operator must conduct a risk assessment 
that analyzes the identified threats and potential consequences of an 
incident for each covered segment. The risk assessment must include 
evaluation of the effects of interacting threats, including the 
potential for interactions of threats and anomalous conditions not 
previously evaluated. An operator must ensure validity of the methods 
used to conduct the risk assessment in light of incident, leak, and 
failure history and other historical information. Validation must 
ensure the risk assessment methods produce a risk characterization that 
is consistent with the operator's and industry experience, including 
evaluations of the cause of past incidents, as determined by root cause 
analysis or other equivalent means, and include sensitivity analysis of 
the

[[Page 20842]]

factors used to characterize both the probability of loss of pipeline 
integrity and consequences of the postulated loss of pipeline 
integrity. An operator must use the risk assessment to determine 
additional preventive and mitigative measures needed (Sec.  192.935) 
for each covered segment, and periodically evaluate the integrity of 
each covered pipeline segment (Sec.  192.937(b)). The risk assessment 
must:
    (1) Analyze how a potential failure could affect high consequence 
areas, including the consequences of the entire worst-case incident 
scenario from initial failure to incident termination;
    (2) Analyze the likelihood of failure due to each individual threat 
or risk factor, and each unique combination of threats or risk factors 
that interact or simultaneously contribute to risk at a common 
location;
    (3) Lead to better understanding of the nature of the threat, the 
failure mechanisms, the effectiveness of currently deployed risk 
mitigation activities, and how to prevent, mitigate, or reduce those 
risks;
    (4) Account for, and compensate for, uncertainties in the model and 
the data used in the risk assessment; and
    (5) Evaluate the potential risk reduction associated with candidate 
risk reduction activities such as preventive and mitigative measures 
and reduced anomaly remediation and assessment intervals.
    (d) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must assess the threats to each covered segment 
using the information in sections 4 and 5 of ASME B31.8S, and consider 
any threats unique to the integrity of plastic pipe such as poor joint 
fusion practices, pipe with poor slow crack growth (SCG) resistance, 
brittle pipe, circumferential cracking, hydrocarbon softening of the 
pipe, internal and external loads, longitudinal or lateral loads, 
proximity to elevated heat sources, and point loading.
    (e) * * *
    (2) Cyclic fatigue. An operator must evaluate whether cyclic 
fatigue or other loading conditions (including ground movement, 
suspension bridge condition) could lead to a failure of a deformation, 
including a dent or gouge, crack, or other defect in the covered 
segment. The evaluation must assume the presence of threats in the 
covered segment that could be exacerbated by cyclic fatigue. An 
operator must use the results from the evaluation together with the 
criteria used to evaluate the significance of this threat to the 
covered segment to prioritize the integrity baseline assessment or 
reassessment. Fracture mechanics modeling for failure stress pressures 
and cyclic fatigue crack growth analysis must be conducted in 
accordance with Sec.  192.624(d) for cracks. Cyclic fatigue analysis 
must be annually, not to exceed 15 months.
    (3) Manufacturing and construction defects. An operator must 
analyze the covered segment to determine the risk of failure from 
manufacturing and construction defects (including seam defects) in the 
covered segment. The analysis must consider the results of prior 
assessments on the covered segment. An operator may consider 
manufacturing and construction related defects to be stable defects 
only if the covered segment has been subjected to hydrostatic pressure 
testing satisfying the criteria of subpart J of this part of at least 
1.25 times MAOP, and the segment has not experienced an in-service 
incident attributed to a manufacturing or construction defect since the 
date of the pressure test. If any of the following changes occur in the 
covered segment, an operator must prioritize the covered segment as a 
high risk segment for the baseline assessment or a subsequent 
reassessment, and must reconfirm or reestablish MAOP in accordance with 
Sec.  192.624(c).
    (i) The segment has experienced an in-service incident, as 
described in Sec.  192.624(a)(1);
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) ERW pipe. If a covered pipeline segment contains low frequency 
electric resistance welded pipe (ERW), lap welded pipe, pipe with seam 
factor less than 1.0 as defined in Sec.  192.113, or other pipe that 
satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3 
and A4.4, and any covered or non-covered segment in the pipeline system 
with such pipe has experienced seam failure (including, but not limited 
to pipe body cracking, seam cracking and selective seam weld 
corrosion), or operating pressure on the covered segment has increased 
over the maximum operating pressure experienced during the preceding 
five years (including abnormal operation as defined in Sec.  
192.605(c)), or MAOP has been increased, an operator must select an 
assessment technology or technologies with a proven application capable 
of assessing seam integrity and seam corrosion anomalies. The operator 
must prioritize the covered segment as a high risk segment for the 
baseline assessment or a subsequent reassessment. Pipe with cracks must 
be evaluated using fracture mechanics modeling for failure stress 
pressures and cyclic fatigue crack growth analysis to estimate the 
remaining life of the pipe in accordance with Sec.  192.624(c) and (d).
* * * * *
0
40. In Sec.  192.921, paragraph (a) is revised to read as follows:


Sec.  192.921  How is the baseline assessment to be conducted?

    (a) Assessment methods. An operator must assess the integrity of 
the line pipe in each covered segment by applying one or more of the 
following methods for each threat to which the covered segment is 
susceptible. An operator must select the method or methods best suited 
to address the threats identified to the covered segment (See Sec.  
192.917). In addition, an operator may use an integrity assessment to 
meet the requirements of this section if the pipeline segment 
assessment is conducted in accordance with the integrity assessment 
requirements of Sec.  192.624(c) for establishing MAOP.
    (1) Internal inspection tool or tools capable of detecting 
corrosion, deformation and mechanical damage (including dents, gouges 
and grooves), material cracking and crack-like defects (including 
stress corrosion cracking, selective seam weld corrosion, 
environmentally assisted cracking, and girth weld cracks), hard spots 
with cracking, and any other threats to which the covered segment is 
susceptible. When performing an assessment using an in-line inspection 
tool, an operator must comply with Sec.  192.493. A person qualified by 
knowledge, training, and experience must analyze the data obtained from 
an internal inspection tool to determine if a condition could adversely 
affect the safe operation of the pipeline. In addition, an operator 
must explicitly consider uncertainties in reported results (including, 
but not limited to, tool tolerance, detection threshold, probability of 
detection, probability of identification, sizing accuracy, conservative 
anomaly interaction criteria, location accuracy, anomaly findings, and 
unity chart plots or equivalent for determining uncertainties and 
verifying actual tool performance) in identifying and characterizing 
anomalies;
    (2) Pressure test conducted in accordance with subpart J of this 
part. An operator must use the test pressures specified in table 3 of 
section 5 of ASME/ANSI B31.8S to justify an extended reassessment 
interval in accordance with Sec.  192.939. The use of pressure testing 
is appropriate for threats such as internal corrosion, external 
corrosion, and other environmentally assisted corrosion mechanisms, 
manufacturing and related defect threats, including defective pipe

[[Page 20843]]

and pipe seams, stress corrosion cracking, selective seam weld 
corrosion, dents and other forms of mechanical damage;
    (3) ``Spike'' hydrostatic pressure test in accordance with Sec.  
192.506. The use of spike hydrostatic pressure testing is appropriate 
for threats such as stress corrosion cracking, selective seam weld 
corrosion, manufacturing and related defects, including defective pipe 
and pipe seams, and other forms of defect or damage involving cracks or 
crack-like defects;
    (4) Excavation and in situ direct examination by means of visual 
examination, direct measurement, and recorded non-destructive 
examination results and data needed to assess all threats, including 
but not limited to, ultrasonic testing (UT), radiography, and magnetic 
particle inspection (MPI);
    (5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in 
Appendix F;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. Use of direct 
assessment is allowed only if the line is not capable of inspection by 
internal inspection tools and is not practical to assess using the 
methods specified in paragraphs (d)(1) through (5) of this section. An 
operator must conduct the direct assessment in accordance with the 
requirements listed in Sec.  192.923 and with the applicable 
requirements specified in Sec.  192.925, 192.927, or 192.929; or
    (7) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe for each of 
the threats to which the pipeline is susceptible. An operator choosing 
this option must notify the Office of Pipeline Safety (OPS) 180 days 
before conducting the assessment, in accordance with Sec.  192.949 and 
receive a ``no objection letter'' from the Associate Administrator of 
Pipeline Safety. An operator must also notify the appropriate State or 
local pipeline safety authority when a covered segment is located in a 
State where OPS has an interstate agent agreement, or an intrastate 
covered segment is regulated by that State.
* * * * *
0
41. In Sec.  192.923, paragraphs (b)(2) and (b)(3) are revised to read 
as follows:


Sec.  192.923  How is direct assessment used and for what threats?

* * * * *
    (b) * * *
    (2) NACE SP0206-2006 and Sec.  192.927 if addressing internal 
corrosion (ICDA).
    (3) NACE SP0204-2008 and Sec.  192.929 if addressing stress 
corrosion cracking (SCCDA).
* * * * *
0
42. In Sec.  192.927, paragraphs (b) and (c) are revised to read as 
follows:


Sec.  192.927  What are the requirements for using Internal Corrosion 
Direct Assessment (ICDA)?

* * * * *
    (b) General requirements. An operator using direct assessment as an 
assessment method to address internal corrosion in a covered pipeline 
segment must follow the requirements in this section and in NACE 
SP0206-2006 (incorporated by reference, see Sec.  192.7). The Dry Gas 
(DG) Internal Corrosion Direct Assessment (ICDA) process described in 
this section applies only for a segment of pipe transporting normally 
dry natural gas (see definition Sec.  192.3), and not for a segment 
with electrolyte normally present in the gas stream. If an operator 
uses ICDA to assess a covered segment operating with electrolyte 
present in the gas stream, the operator must develop a plan that 
demonstrates how it will conduct ICDA in the segment to effectively 
address internal corrosion, and must notify the Office of Pipeline 
Safety (OPS) 180 days before conducting the assessment in accordance 
with Sec.  192.921(a)(4) or Sec.  192.937(c)(4).
    (c) The ICDA plan. An operator must develop and follow an ICDA plan 
that meets all requirements and recommendations contained in NACE 
SP0206-2006 and that implements all four steps of the DG-ICDA process 
including pre-assessment, indirect inspection, detailed examination, 
and post-assessment. The plan must identify where all ICDA Regions with 
covered segments are located in the transmission system. An ICDA Region 
is a continuous length of pipe (including weld joints) uninterrupted by 
any significant change in water or flow characteristics that includes 
similar physical characteristics or operating history. An ICDA Region 
extends from the location where liquid may first enter the pipeline and 
encompasses the entire area along the pipeline where internal corrosion 
may occur until a new input introduces the possibility of water 
entering the pipeline. In cases where a single covered segment is 
partially located in two or more ICDA regions, the four-step ICDA 
process must be completed for each ICDA region in which the covered 
segment is partially located in order to complete the assessment of the 
covered segment.
    (1) Preassessment. An operator must comply with the requirements 
and recommendations in NACE SP0206-2006 in conducting the preassessment 
step of the ICDA process.
    (2) Indirect Inspection. An operator must comply with the 
requirements and recommendations in NACE SP0206-2006, and the following 
additional requirements, in conducting the Indirect Inspection step of 
the ICDA process. Operators must explicitly document the results of its 
feasibility assessment as required by NACE SP0206-2006, Section 3.3; if 
any condition that precludes the successful application of ICDA 
applies, then ICDA may not be used, and another assessment method must 
be selected. When performing the indirect inspection, the operator must 
use pipeline specific data, exclusively. The use of assumed pipeline or 
operational data is prohibited. When calculating the critical 
inclination angle of liquid holdup and the inclination profile of the 
pipeline, the operator must consider the accuracy, reliability, and 
uncertainty of data used to make those calculations, including but not 
limited to gas flow velocity (including during upset conditions), 
pipeline elevation profile survey data (including specific profile at 
features with inclinations such as road crossing, river crossings, 
drains, valves, drips, etc.), topographical data, depth of cover, etc. 
The operator must select locations for direct examination, and 
establish the extent of pipe exposure needed (i.e., the size of the 
bell hole), to explicitly account for these uncertainties and their 
cumulative effect on the precise location of predicted liquid dropout.
    (3) Detailed examination. An operator must comply with the 
requirements and recommendations in NACE SP0206-2006 in conducting the 
detailed examination step of the ICDA process. In addition, on the 
first use of ICDA for a covered segment, an operator must identify a 
minimum of two locations for excavation within each covered segment 
associated with the ICDA Region and must perform a detailed examination 
for internal corrosion at each location using ultrasonic thickness 
measurements, radiography, or other generally accepted measurement 
techniques. One location must be the low point (e.g., sags, drips, 
valves, manifolds, dead-legs, traps) within the covered segment nearest 
to the beginning of the ICDA Region. The second location must be 
further downstream, within a covered segment, near the end of the ICDA 
Region. If corrosion is found at any location, the operator must--
    (i) Evaluate the severity of the defect (remaining strength) and 
remediate the defect in accordance with Sec.  192.933, if the condition 
is in a covered segment,

[[Page 20844]]

or in accordance with Sec. Sec.  192.485 and 192.713 if the condition 
is not in a covered segment;
    (ii) Expand the detailed examination program, whenever internal 
corrosion is discovered, to determine all locations that have internal 
corrosion within the ICDA region, and accurately characterize the 
nature, extent, and root cause of the internal corrosion. In cases 
where the internal corrosion was identified within the ICDA region but 
outside the covered segment, the expanded detailed examination program 
must also include at least two detailed examinations within each 
covered segment associated with the ICDA region, at the location within 
the covered segment(s) most likely to have internal corrosion. One 
location must be the low point (e.g., sags, drips, valves, manifolds, 
dead-legs, traps) within the covered segment nearest to the beginning 
of the ICDA Region. The second location must be further downstream, 
within the covered segment. In instances of first use of ICDA for a 
covered segment, where these locations have already been examined per 
paragraph (c)(3) of this section, two additional detailed examinations 
must be conducted within the covered segment; and
    (iii) Expand the detailed examination program to evaluate the 
potential for internal corrosion in all pipeline segments (both covered 
and non-covered) in the operator's pipeline system with similar 
characteristics to the ICDA region in which the corrosion was found and 
remediate identified instances of internal corrosion in accordance with 
Sec.  192.933 or Sec.  192.713, as appropriate.
    (4) Post-assessment evaluation and monitoring. An operator must 
comply with the requirements and recommendations in NACE SP0206-2006 in 
performing the post assessment step of the ICDA process. In addition to 
the post-assessment requirements and recommendations in NACE SP0206-
2006, the evaluation and monitoring process must also include--
    (i) Evaluating the effectiveness of ICDA as an assessment method 
for addressing internal corrosion and determining whether a covered 
segment should be reassessed at more frequent intervals than those 
specified in Sec.  192.939. An operator must carry out this evaluation 
within a year of conducting an ICDA;
    (ii) Validation of the flow modeling calculations by comparison of 
actual locations of discovered internal corrosion with locations 
predicted by the model (if the flow model cannot be validated, then 
ICDA is not feasible for the segment); and
    (iii) Continually monitoring each ICDA region which contains a 
covered segment where internal corrosion has been identified by using 
techniques such as coupons or UT sensors or electronic probes, and by 
periodically drawing off liquids at low points and chemically analyzing 
the liquids for the presence of corrosion products. An operator must 
base the frequency of the monitoring and liquid analysis on results 
from all integrity assessments that have been conducted in accordance 
with the requirements of this subpart, and risk factors specific to the 
ICDA region. At a minimum, the monitoring frequency must be two times 
each calendar year, but at intervals not exceeding 7\1/2\ months. If an 
operator finds any evidence of corrosion products in the ICDA region, 
the operator must take prompt action in accordance with one of the two 
following required actions and remediate the conditions the operator 
finds in accordance with Sec.  192.933.
    (A) Conduct excavations of, and detailed examinations at, locations 
downstream from where the electrolyte might have entered the pipe to 
investigate and accurately characterize the nature, extent, and root 
cause of the corrosion, including the monitoring and mitigation 
requirements of Sec.  192.478; or
    (B) Assess the covered segment using ILI tools capable of detecting 
internal corrosion.
    (5) Other requirements--The ICDA plan must also include the 
following:
    (i) Criteria an operator will apply in making key decisions (e.g., 
ICDA feasibility, definition of ICDA Regions and Sub-regions, 
conditions requiring excavation) in implementing each stage of the ICDA 
process;
    (ii) Provisions that analysis be carried out on the entire pipeline 
in which covered segments are present, except that application of the 
remediation criteria of Sec.  192.933 may be limited to covered 
segments.
0
43. Section 192.929 is revised to read as follows:


Sec.  192.929  What are the requirements for using direct assessment 
for stress corrosion cracking (SCCDA)?

    (a) Definition. Stress corrosion cracking direct assessment (SCCDA) 
is a process to assess a covered pipe segment for the presence of SCC 
by systematically gathering and analyzing excavation data for pipe 
having similar operational characteristics and residing in a similar 
physical environment.
    (b) General requirements. An operator using direct assessment as an 
integrity assessment method to address stress corrosion cracking in a 
covered pipeline segment must develop and follow an SCCDA plan that 
meets all requirements and recommendations contained in NACE SP0204-
2008 and that implements all four steps of the SCCDA process including 
pre-assessment, indirect inspection, detailed examination and post-
assessment. As specified in NACE SP0204-2008, Section 1.1.7, SCCDA is 
complementary with other inspection methods such as in-line inspection 
(ILI) or hydrostatic testing and is not necessarily an alternative or 
replacement for these methods in all instances. In addition, the plan 
must provide for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data for all covered 
segments to identify whether the conditions for SCC are present and to 
prioritize the covered segments for assessment in accordance with NACE 
SP0204-2008, sections 3 and 4, and table 1. This process must also 
include gathering and evaluating data related to SCC at all sites an 
operator excavates during the conduct of its pipeline operations (both 
within and outside covered segments) where the criteria in NACE SP0204-
2008 indicate the potential for SCC. This data gathering process must 
be conducted in accordance with NACE SP0204-2008, section 5.3, and must 
include, at minimum, all data listed in NACE SP0204-2008, table 2. 
Further, the following factors must be analyzed as part of this 
evaluation:
    (i) The effects of a carbonate-bicarbonate environment, including 
the implications of any factors that promote the production of a 
carbonate-bicarbonate environment such as soil temperature, moisture, 
the presence or generation of carbon dioxide, and/or Cathodic 
Protection (CP).
    (ii) The effects of cyclic loading conditions on the susceptibility 
and propagation of SCC in both high-pH and near-neutral-pH 
environments.
    (iii) The effects of variations in applied CP such as 
overprotection, CP loss for extended periods, and high negative 
potentials.
    (iv) The effects of coatings that shield CP when disbonded from the 
pipe.
    (v) Other factors which affect the mechanistic properties 
associated with SCC including but not limited to historical and 
present-day operating pressures, high tensile residual stresses, 
flowing product temperatures, and the presence of sulfides.
    (2) Indirect inspection. In addition to the requirements and 
recommendations of NACE SP0204-2008, section 4, the

[[Page 20845]]

plan's procedures for indirect inspection must include provisions for 
conducting at least two above ground surveys using complementary 
measurement tools most appropriate for the pipeline segment based on 
the data gathering and integration step.
    (3) Direct examination. In addition to the requirements and 
recommendations of NACE SP0204-2008, the plan's procedures for direct 
examination must provide for conducting a minimum of three direct 
examinations within the SCC segment at locations determined to be the 
most likely for SCC to occur.
    (4) Remediation and mitigation. If any indication of SCC is 
discovered in a segment, an operator must mitigate the threat in 
accordance with one of the following applicable methods:
    (i) Removing the pipe with SCC, remediating the pipe with a Type B 
sleeve, hydrostatic testing in accordance with (b)(4)(ii), below, or by 
grinding out the SCC defect and repairing the pipe. If grinding is used 
for repair, the repair procedure must include: Nondestructive testing 
for any remaining cracks or other defects; measuring remaining wall 
thickness; and the remaining strength of the pipe at the repair 
location must be determined using ASME/ANSI B31G or RSTRENG and must be 
sufficient to meet the design requirements of subpart C of this part. 
Pipe and material properties used in remaining strength calculations 
must be documented in reliable, traceable, verifiable, and complete 
records. If such records are not available, pipe and material 
properties used in the remaining strength calculations must be based on 
properties determined and documented in accordance with Sec.  192.607.
    (ii) Significant SCC must be mitigated using a hydrostatic testing 
program to a minimum test pressure equal to 105 percent of the 
specified minimum yield strength of the pipe for 30 minutes immediately 
followed by a pressure test in accordance with Sec.  192.506, but not 
lower than 1.25 times MAOP. The test pressure for the entire sequence 
must be continuously maintained for at least 8 hours, in accordance 
with Sec.  192.506 and must be above the minimum test factors in Sec.  
192.619(a)(2)(ii) or 192.620(a)(2)(ii), but not lower than 1.25 times 
maximum allowable operating pressure. Any test failures due to SCC must 
be repaired by replacement of the pipe segment, and the segment re-
tested until the pipe passes the complete test without leakage. Pipe 
segments that have SCC present, but that pass the pressure test, may be 
repaired by grinding in accordance with paragraph (b)(4)(i) of this 
section.
    (5) Post assessment. In addition to the requirements and 
recommendations of NACE SP0204-2008, sections 6.3, periodic 
reassessment, and 6.4, effectiveness of SCCDA, the operator's 
procedures for post assessment must include development of a 
reassessment plan based on the susceptibility of the operator's pipe to 
SCC as well as on the mechanistic behavior of identified cracking. 
Reassessment intervals must comply with Sec.  192.939. Factors that 
must be considered include, but are not limited to:
    (i) Evaluation of discovered crack clusters during the direct 
examination step in accordance with NACE RP0204-2008, sections 5.3.5.7, 
5.4, and 5.5;
    (ii) Conditions conducive to creation of the carbonate-bicarbonate 
environment;
    (iii) Conditions in the application (or loss) of CP that can create 
or exacerbate SCC;
    (iv) Operating temperature and pressure conditions including 
operating stress levels on the pipe;
    (v) Cyclic loading conditions;
    (vi) Mechanistic conditions that influence crack initiation and 
growth rates;
    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and.
    (ix) Disbonded coatings that shield CP from the pipe.
0
44. In Sec.  192.933, paragraphs (a)(1), (b), (d)(1) are revised and 
paragraphs (d)(2)(iii) through (vii) are added to read as follows:


Sec.  192.933  What actions must be taken to address integrity issues?

    (a) * * *
    (1) Temporary pressure reduction. If an operator is unable to 
respond within the time limits for certain conditions specified in this 
section, the operator must temporarily reduce the operating pressure of 
the pipeline or take other action that ensures the safety of the 
covered segment. An operator must determine any temporary reduction in 
operating pressure required by this section using ASME/ANSI B31G 
(incorporated by reference, see Sec.  192.7) or AGA Pipeline Research 
Council International, PR-3-805 (R-STRENG) (incorporated by reference, 
see Sec.  192.7) to determine the safe operating pressure that restores 
the safety margin commensurate with the design factor for the Class 
Location in which the affected pipeline is located, or reduce the 
operating pressure to a level not exceeding 80 percent of the operating 
pressure at the time the condition was discovered. Pipe and material 
properties used in remaining strength calculations must be documented 
in reliable, traceable, verifiable, and complete records. If such 
records are not available, pipe and material properties used in the 
remaining strength calculations must be based on properties determined 
and documented in accordance with Sec.  192.607. An operator must 
notify PHMSA in accordance with Sec.  192.949 if it cannot meet the 
schedule for evaluation and remediation required under paragraph (c) of 
this section and cannot provide safety through temporary reduction in 
operating pressure or other action. An operator must also notify a 
State pipeline safety authority when either a covered segment is 
located in a State where PHMSA has an interstate agent agreement, or an 
intrastate covered segment is regulated by that State.
* * * * *
    (b) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. For the purposes of this section, a condition that presents a 
potential threat includes, but is not limited to, those conditions that 
require remediation or monitoring listed under paragraphs (d)(1) 
through (3) of this section. An operator must promptly, but no later 
than 180 days after conducting an integrity assessment, obtain 
sufficient information about a condition to make that determination, 
unless the operator demonstrates that the 180-day period is 
impracticable. In cases where a determination is not made within the 
180-day period the operator must notify OPS, in accordance with Sec.  
192.949, and provide an expected date when adequate information will 
become available.
* * * * *
    (d) * * *
    (1) Immediate repair conditions. An operator's evaluation and 
remediation schedule must follow ASME/ANSI B31.8S, section 7 in 
providing for immediate repair conditions. To maintain safety, an 
operator must temporarily reduce operating pressure in accordance with 
paragraph (a) of this section or shut down the pipeline until the 
operator completes the repair of these conditions. An operator must 
treat the following conditions as immediate repair conditions:
    (i) Calculation of the remaining strength of the pipe shows a 
predicted failure pressure less than or equal to 1.1 times the maximum 
allowable operating pressure at the location of the anomaly for any 
class location. Suitable

[[Page 20846]]

remaining strength calculation methods include ASME/ANSI B31G 
(incorporated by reference, see Sec.  192.7), PRCI PR-3-805 (R-STRENG) 
(incorporated by reference, see Sec.  192.7); or an alternative method 
of remaining strength calculation that will provide an equally 
conservative result. Pipe and material properties used in remaining 
strength calculations must be documented in reliable, traceable, 
verifiable, and complete records. If such records are not available, 
pipe and material properties used in the remaining strength 
calculations must be based on properties determined and documented in 
accordance with Sec.  192.607.
    (ii) A dent that has any indication of metal loss, cracking, or a 
stress riser.
    (iii) An indication or anomaly that in the judgment of the person 
designated by the operator to evaluate the assessment results requires 
immediate action.
    (iv) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (v) An indication of metal-loss affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency, or high 
frequency electric resistance welding or by electric flash welding.
    (vi) Any indication of significant stress corrosion cracking (SCC).
    (vii) Any indication of significant selective seam weld corrosion 
(SSWC).
    (2) * * *.
    (iii) A calculation of the remaining strength of the pipe shows a 
predicted failure pressure ratio at the location of the anomaly less 
than or equal to 1.25 for Class 1 locations, 1.39 for Class 2 
locations, 1.67 for Class 3 locations, and 2.00 for Class 4 locations.
    (iv) An area of general corrosion with a predicted metal loss 
greater than 50% of nominal wall.
    (v) Predicted metal loss greater than 50% of nominal wall that is 
located at a crossing of another pipeline, or is in an area with 
widespread circumferential corrosion, or is in an area that could 
affect a girth weld.
    (vi) A gouge or groove greater than 12.5% of nominal wall.
    (vii) Any indication of crack or crack-like defect other than an 
immediate condition.
* * * * *
0
45. In Sec.  192.935, paragraphs (a), (b)(2), and (d)(3) are revised 
and paragraphs (f) and (g) are added to read as follows:


Sec.  192.935  What additional preventive and mitigative measures must 
an operator take?

    (a) General requirements. An operator must take additional measures 
beyond those already required by part 192 to prevent a pipeline failure 
and to mitigate the consequences of a pipeline failure in a high 
consequence area. Such additional measures must be based on the risk 
analyses required by Sec.  192.917, and must include, but are not 
limited to: Correction of the root causes of past incidents to prevent 
recurrence; establishing and implementing adequate operations and 
maintenance processes that could increase safety; establishing and 
deploying adequate resources for successful execution of preventive and 
mitigative measures; installing automatic shut-off valves or remote 
control valves; installing pressure transmitters on both sides of 
automatic shut-off valves and remote control valves that communicate 
with the pipeline control center; installing computerized monitoring 
and leak detection systems; replacing pipe segments with pipe of 
heavier wall thickness or higher strength; conducting additional right-
of-way patrols; conducting hydrostatic tests in areas where material 
has quality issues or lost records; tests to determine material 
mechanical and chemical properties for unknown properties that are 
needed to assure integrity or substantiate MAOP evaluations including 
material property tests from removed pipe that is representative of the 
in-service pipeline; re-coating of damaged, poorly performing or 
disbonded coatings; applying additional depth-of-cover survey at roads, 
streams and rivers; remediating inadequate depth-of-cover; providing 
additional training to personnel on response procedures, conducting 
drills with local emergency responders; and implementing additional 
inspection and maintenance programs.
    (b) * * *
    (2) Outside force damage. If an operator determines that outside 
force (e.g., earth movement, loading, longitudinal, or lateral forces, 
seismicity of the area, floods, unstable suspension bridge) is a threat 
to the integrity of a covered segment, the operator must take measures 
to minimize the consequences to the covered segment from outside force 
damage. These measures include, but are not limited to, increasing the 
frequency of aerial, foot or other methods of patrols, adding external 
protection, reducing external stress, relocating the line, or 
geospatial, GIS, and deformation in-line inspections.
* * * * *
    (d) * * *
    (3) Perform semi-annual, instrumented leak surveys (quarterly for 
unprotected pipelines or cathodically protected pipe where indirect 
assessments, i.e. indirect examination tool/method such as close 
interval survey, alternating current voltage gradient, direct current 
voltage gradient, or equivalent, are impractical).
* * * * *
    (f) Internal corrosion. As an operator gains information about 
internal corrosion, it must enhance its internal corrosion management 
program, as required under subpart I of this part, with respect to a 
covered segment to prevent and minimize the consequences of a release 
due to internal corrosion. At a minimum, as part of this enhancement, 
operators must--
    (1) Monitor for, and mitigate the presence of, deleterious gas 
stream constituents.
    (2) At points where gas with potentially deleterious contaminants 
enters the pipeline, use filter separators or separators and continuous 
gas quality monitoring equipment.
    (3) At least once per quarter, use gas quality monitoring equipment 
that includes, but is not limited to, a moisture analyzer, 
chromatograph, carbon dioxide sampling, and hydrogen sulfide sampling.
    (4) Use cleaning pigs and sample accumulated liquids and solids, 
including tests for microbiologically induced corrosion.
    (5) Use inhibitors when corrosive gas or corrosive liquids are 
present.
    (6) Address potentially corrosive gas stream constituents as 
specified in Sec.  192.478(a), where the volumes exceed these amounts 
over a 24-hour interval in the pipeline as follows:
    (i) Limit carbon dioxide to three percent by volume;
    (ii) Allow no free water and otherwise limit water to seven pounds 
per million cubic feet of gas; and
    (iii) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet 
(16 ppm) of gas. If the hydrogen sulfide concentration is greater than 
0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging 
and inhibitor injection program to address deleterious gas stream 
constituents, including follow-up sampling and quality testing of 
liquids at receipt points.
    (7) Review the program at least semi-annually based on the gas 
stream experience and implement adjustments to monitor for, and 
mitigate the presence of, deleterious gas stream constituents.
    (g) External corrosion. As an operator gains information about 
external corrosion, it must enhance its external corrosion management 
program, as required under subpart I of this part, with respect to a 
covered segment to

[[Page 20847]]

prevent and minimize the consequences of a release due to external 
corrosion. At a minimum, as part of this enhancement, operators must--
    (1) Control electrical interference currents that can adversely 
affect cathodic protection as follows:
    (i) As frequently as needed (such as when new or uprated high 
voltage alternating current power lines greater than or equal to 69 kVA 
or electrical substations are co-located near the pipeline), but not to 
exceed every seven years, perform the following:
    (A) Conduct an interference survey (at times when voltages are at 
the highest values for a time period of at least 24-hours) to detect 
the presence and level of any electrical current that could impact 
external corrosion where interference is suspected;
    (B) Analyze the results of the survey to identify locations where 
interference currents are greater than or equal to 20 Amps per meter 
squared; and
    (C) Take any remedial action needed within six months after 
completing the survey to protect the pipeline segment from deleterious 
current. Remedial action means the implementation of measures 
including, but not limited to, additional grounding along the pipeline 
to reduce interference currents. Any location with interference 
currents greater than 50 Amps per meter squared must be remediated. If 
any AC interference between 20 and 50 Amps per meter squared is not 
remediated, the operator must provide and document an engineering 
justification.
    (2) Confirm the adequacy of external corrosion control through 
indirect assessment as follows:
    (i) Periodically (as frequently as needed but at intervals not to 
exceed seven years) assess the adequacy of the cathodic protection 
through an indirect method such as close-interval survey, and the 
integrity of the coating using direct current voltage gradient (DCVG) 
or alternating current voltage gradient (ACVG).
    (ii) Remediate any damaged coating with a voltage drop classified 
as moderate or severe (IR drop greater than 35% for DCVG or 50 
dB[micro]v for ACVG) under section 4 of NACE RP0502-2008 (incorporated 
by reference, see Sec.  192.7).
    (iii) Integrate the results of the indirect assessment required 
under paragraph (g)(2)(i) of this section with the results of the most 
recent integrity assessment required by this subpart and promptly take 
any needed remedial actions no later than 6 months after assessment 
finding.
    (iv) Perform periodic assessments as follows:
    (A) Conduct periodic close interval surveys with current 
interrupted to confirm voltage drops in association with integrity 
assessments under sections Sec. Sec.  192.921 and 192.937 of this 
subpart.
    (B) Locate pipe-to-soil test stations at half-mile intervals within 
each covered segment, ensuring at least one station is within each high 
consequence area, if practicable.
    (C) Integrate the results with those of the baseline and periodic 
assessments for integrity done under sections Sec. Sec.  192.921 and 
192.937 of this subpart.
    (3) Control external corrosion through cathodic protection as 
follows:
    (i) If an annual test station reading indicates cathodic protection 
below the level of protection required in subpart I of this part, 
complete assessment and remedial action, as required in Sec.  
192.465(f), within 6 months of the failed reading or notify each PHMSA 
pipeline safety regional office where the pipeline is in service and 
demonstrate that the integrity of the pipeline is not compromised if 
the repair takes longer than 6 months. An operator must also notify a 
State pipeline safety authority when the pipeline is located in a State 
where PHMSA has an interstate agent agreement, or an intrastate 
pipeline is regulated by that State; and
    (ii) Remediate insufficient cathodic protection levels or areas 
where protective current is found to be leaving the pipeline in 
accordance with paragraph (g)(3)(i) of this section, including use of 
indirect assessments or direct examination of the coating in areas of 
low CP readings unless the reason for the failed reading is determined 
to be a short to an adjacent foreign structure, rectifier connection or 
power input problem that can be remediated and restoration of adequate 
cathodic protection can be verified. The operator must confirm 
restoration of adequate corrosion control by a close interval survey on 
both sides of the affected test stations to the adjacent test stations.
0
46. In Sec.  192.937, paragraphs (b) and (c) are revised to read as 
follows:


Sec.  192.937  What is a continual process of evaluation and assessment 
to maintain a pipeline's integrity?

* * * * *
    (b) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure the integrity of each covered segment. 
The periodic evaluation must be based on a data integration and risk 
assessment of the entire pipeline as specified in Sec.  192.917, which 
incorporates an analysis of updated pipeline design, construction, 
operation, maintenance, and integrity information. For plastic 
transmission pipelines, the periodic evaluation is based on the threat 
analysis specified in Sec.  192.917(d). For all other transmission 
pipelines, the evaluation must consider the past and present integrity 
assessment results, data integration and risk assessment information 
(Sec.  192.917), and decisions about remediation (Sec.  192.933). The 
evaluation must identify the threats specific to each covered segment, 
including interacting threats and the risk represented by these 
threats, and identify additional preventive and mitigative measures 
(Sec.  192.935) to avert or reduce risks.
    (c) Assessment methods. An operator must assess the integrity of 
the line pipe in each covered segment by applying one or more of the 
following methods for each threat to which the covered segment is 
susceptible. An operator must select the method or methods best suited 
to address the threats identified to the covered segment (See Sec.  
192.917). An operator may use an integrity assessment to meet the 
requirements of this section if the pipeline segment assessment is 
conducted in accordance with the integrity assessment requirements of 
Sec.  192.624(c) for establishing MAOP.
    (1) Internal inspection tool or tools capable of detecting 
corrosion, deformation and mechanical damage (including dents, gouges 
and grooves), material cracking and crack-like defects (including 
stress corrosion cracking, selective seam weld corrosion, 
environmentally assisted cracking, and girth weld cracks), hard spots, 
and any other threats to which the covered segment is susceptible. When 
performing an assessment using an in-line inspection tool, an operator 
must comply with Sec.  192.493. 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. In addition, an operator must explicitly consider 
uncertainties in reported results (including, but not limited to, tool 
tolerance, detection threshold, probability of detection, probability 
of identification, sizing accuracy, conservative anomaly interaction 
criteria, location accuracy, anomaly findings, and unity chart plots or 
equivalent for determining uncertainties and verifying tool 
performance) in identifying and characterizing anomalies.
    (2) Pressure test conducted in accordance with subpart J of this 
part.

[[Page 20848]]

An operator must use the test pressures specified in table 3 of section 
5 of ASME/ANSI B31.8S to justify an extended reassessment interval in 
accordance with Sec.  192.939. The use of pressure testing is 
appropriate for time dependent threats such as internal corrosion, 
external corrosion, and other environmentally assisted corrosion 
mechanisms and for manufacturing and related defect threats, including 
defective pipe and pipe seams.
    (3) ``Spike'' hydrostatic pressure test in accordance with Sec.  
192.506. The use of spike hydrostatic pressure testing is appropriate 
for threats such as stress corrosion cracking, selective seam weld 
corrosion, manufacturing and related defects, including defective pipe 
and pipe seams, and other forms of defect or damage involving cracks or 
crack-like defects.
    (4) Excavation and in situ direct examination by means of visual 
examination, direct measurement, and recorded non-destructive 
examination results and data needed to assess all threats, including 
but not limited to, ultrasonic testing (UT), radiography, and magnetic 
particle inspection (MPI). An operator must explicitly consider 
uncertainties in in situ direct examination results (including, but not 
limited to, tool tolerance, detection threshold, probability of 
detection, probability of identification, sizing accuracy, and usage 
unity chart plots or equivalent for determining uncertainties and 
verifying performance on the type defects being evaluated) in 
identifying and characterizing anomalies.
    (5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in 
Appendix F;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. Use of direct 
assessment is allowed only if the line is not capable of inspection by 
internal inspection tools and is not practical to assess using the 
methods specified in paragraphs (c)(1) through (5) of this section. An 
operator must conduct the direct assessment in accordance with the 
requirements listed in Sec.  192.923 and with the applicable 
requirements specified in Sec.  192.925, 192.927, or 192.929;
    (7) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify the Office of Pipeline Safety (OPS) 
180 days before conducting the assessment, in accordance with Sec.  
192.949 and receive a ``no objection letter'' from the Associate 
Administrator of Pipeline Safety. An operator must also notify the 
appropriate State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement, or an intrastate covered segment is regulated by that State.
    (8) Confirmatory direct assessment when used on a covered segment 
that is scheduled for reassessment at a period longer than seven years. 
An operator using this reassessment method must comply with Sec.  
192.931.
0
47. In Sec.  192.939, the introductory text of paragraph (a) is revised 
to read as follows:


Sec.  192.939  What are the required reassessment intervals?

* * * * *
    (a) Pipelines operating at or above 30% SMYS. An operator must 
establish a reassessment interval for each covered segment operating at 
or above 30% SMYS in accordance with the requirements of this section. 
The maximum reassessment interval by an allowable reassessment method 
is seven calendar years. Operators may request a six month extension of 
the seven-calendar year reassessment interval if the operator submits 
written notice to OPS, in accordance with Sec.  192.949, with 
sufficient justification of the need for the extension. If an operator 
establishes a reassessment interval that is greater than seven calendar 
years, the operator must, within the seven-calendar year period, 
conduct a confirmatory direct assessment on the covered segment, and 
then conduct the follow-up reassessment at the interval the operator 
has established. A reassessment carried out using confirmatory direct 
assessment must be done in accordance with Sec.  192.931. The table 
that follows this section sets forth the maximum allowed reassessment 
intervals.
* * * * *
0
48. In Sec.  192.941, paragraphs (b)(1) and the introductory text to 
(b)(2) are revised to read as follows:


Sec.  192.941  What is a low stress reassessment?

* * * * *
    (b) * * *
    (1) Cathodically protected pipe. To address the threat of external 
corrosion on cathodically protected pipe in a covered segment, an 
operator must perform an indirect assessment (i.e. indirect examination 
tool/method such as close interval survey, alternating current voltage 
gradient, direct current voltage gradient, or equivalent) at least 
every seven years on the covered segment. An operator must use the 
results of each indirect assessment as part of an overall evaluation of 
the cathodic protection and corrosion threat for the covered segment. 
This evaluation must consider, at minimum, the leak repair and 
inspection records, corrosion monitoring records, exposed pipe 
inspection records, and the pipeline environment.
    (2) Unprotected pipe or cathodically protected pipe where indirect 
assessments are impractical. If an indirect assessment is impractical 
on the covered segment an operator must--
* * * * *
0
49. Appendix A to part 192 is revised to read as follows:

Appendix A to Part 192--Records Retention Schedule for Transmission 
Pipelines

    Appendix A summarizes the part 192 records retention 
requirements. As required by Sec.  192.13(e), records must be 
readily retrievable and must be reliable, traceable, verifiable, and 
complete.

----------------------------------------------------------------------------------------------------------------
                                                                Summary of records
                                                                requirement (Note:
                                                              referenced code section
          Code section                 Section title         specifies  requirements.         Retention time
                                                             This summary provided for
                                                                convenience only.)
----------------------------------------------------------------------------------------------------------------
                                               Subpart A--General
----------------------------------------------------------------------------------------------------------------
Sec.   192.5(d).................  Class locations........  Records that demonstrate how  Life of pipeline.
                                                            an operator determined
                                                            class locations and the
                                                            actual class locations.
Sec.   192.13(e)................  What general             Records that demonstrate      As specified in this
                                   requirements apply to    compliance with this part.    appendix.
                                   pipelines regulated      At a minimum, operators
                                   under this part?.        must prepare and maintain
                                                            the records specified in
                                                            appendix A to part 192.

[[Page 20849]]

 
Sec.   192.14(b)................  Conversion to service    Records of investigations,    Life of pipeline.
                                   subject to this part.    tests, repairs,
                                                            replacements, and
                                                            alterations made under the
                                                            requirements of Sec.
                                                            192.14(a).
Sec.   192.16(d)................  Customer notification..  Records of a copy of the      3 years.
                                                            notice currently in use and
                                                            evidence that notices have
                                                            been sent to customers.
----------------------------------------------------------------------------------------------------------------
                                              Subpart B--Materials
----------------------------------------------------------------------------------------------------------------
Sec.   192.67...................  Records: Materials and   Records for steel pipe        Life of pipeline.
                                   pipe.                    manufacturing tests,
                                                            inspections, and attributes.
----------------------------------------------------------------------------------------------------------------
                                             Subpart C--Pipe Design
----------------------------------------------------------------------------------------------------------------
Sec.   192.112..................  Additional design        Records for alternative MAOP  Life of pipeline.
                                   requirements for steel   demonstrating compliance
                                   pipe using alternative   with this section.
                                   maximum allowable
                                   operating pressure.
Sec.   192.127..................  Records: Pipe Design     Design records for external   Life of pipeline.
                                   for External Loads and   loads and internal pressure.
                                   Internal Pressures.
----------------------------------------------------------------------------------------------------------------
                                    Subpart D--Design of Pipeline Components
----------------------------------------------------------------------------------------------------------------
Sec.   192.144..................  Qualifying metallic      Records indicating            Life of pipeline.
                                   components.              manufacturer and pressure
                                                            ratings of metallic
                                                            components.
Sec.   192.150..................  Passage of internal      Records of each new           Life of pipeline.
                                   inspection devices.      transmission line
                                                            replacement of pipe,
                                                            valves, fittings, or other
                                                            line component showing that
                                                            the replacement is
                                                            constructed to accommodate
                                                            internal inspection devices
                                                            as required by Sec.
                                                            192.150.
Sec.   192.153..................  Components fabricated    Records of strength tests...  Life of pipeline.
                                   by welding.
Sec.   192.205..................  Records: Pipeline        Records documenting the       Life of pipeline.
                                   components.              manufacturing standard,
                                                            tests, and pressure rating
                                                            to which valves, flanges,
                                                            fittings, branch
                                                            connections, extruded
                                                            outlets, anchor forgings,
                                                            tap connections, and other
                                                            components were
                                                            manufactured and tested in
                                                            accordance with this
                                                            subpart.
----------------------------------------------------------------------------------------------------------------
                                    Subpart E--Welding of Steel in Pipelines
----------------------------------------------------------------------------------------------------------------
Sec.   192.225(b)...............  Welding procedures.....  Records of welding            Life of pipeline.
                                                            procedures, including
                                                            results of qualifying
                                                            procedure tests.
Sec.   192.227(c)...............  Qualification of         Records demonstrating welder  Life of pipeline.
                                   welders and welding      qualification.
                                   operators.
Sec.   192.243(f)...............  Nondestructive testing.  Records showing by milepost,  Life of pipeline.
                                                            engineering station, or by
                                                            geographic feature, the
                                                            number of girth welds made,
                                                            the number nondestructively
                                                            tested, the number
                                                            rejected, and the
                                                            disposition of the rejects.
----------------------------------------------------------------------------------------------------------------
                              Subpart F--Joining of Materials Other Than by Welding
----------------------------------------------------------------------------------------------------------------
Sec.   192.283..................  Plastic pipe:            Records of joining            Life of pipeline.
                                   Qualifying joining       procedures, including
                                   procedures.              results of qualifying
                                                            procedure tests.
Sec.   192.285(e)...............  Plastic pipe:            Records demonstrating         Life of pipeline.
                                   Qualifying persons to    plastic pipe joining
                                   make joints.             qualifications.
----------------------------------------------------------------------------------------------------------------
                  Subpart G--General Construction Requirements for Transmission Lines and Mains
----------------------------------------------------------------------------------------------------------------
Sec.   192.303..................  Compliance with          Records of written            Life of pipeline.
                                   specifications or        specifications or standards
                                   standards.               that apply to each
                                                            transmission line or main.
Sec.   192.305..................  Inspection: General....  Transmission line or main     Life of pipeline.
                                                            inspections.
Sec.   192.307..................  Inspection of materials  Pipe and component materials  Life of pipeline.
                                                            inspections.
Sec.   192.319(d)...............  Installation of pipe in  Records documenting the       Life of pipeline.
                                   a ditch.                 coating assessment findings
                                                            and repairs.
Sec.   192.328..................  Additional construction  Records for alternative MAOP  Life of pipeline.
                                   requirements for steel   demonstrating compliance
                                   pipe using alternative   with this section
                                   maximum allowable        including: quality
                                   operating pressure.      assurance, girth weld non-
                                                            destructive examinations,
                                                            depth of cover, initial
                                                            strength testing (pressure
                                                            tests and root cause
                                                            analysis of failed pipe),
                                                            and impacts of interference
                                                            currents.
----------------------------------------------------------------------------------------------------------------

[[Page 20850]]

 
                        Subpart H--Customer Meters, Service Regulators, and Service Lines
----------------------------------------------------------------------------------------------------------------
Sec.   192.383..................  Excess flow valve        Number of excess flow valves  Life of pipeline.
                                   installation.            installed, as reported as
                                                            part of annual report.
----------------------------------------------------------------------------------------------------------------
                                  Subpart I--Requirements for Corrosion Control
----------------------------------------------------------------------------------------------------------------
Sec.   192.452(a)...............  How does this subpart    Records demonstrating         Life of pipeline.
                                   apply to converted       compliance by the
                                   pipelines and            applicable deadlines.
                                   regulated onshore
                                   gathering lines?.
Sec.   192.459..................  Exposed buried pipe      Records of examinations for   Life of pipeline.
                                   inspection.              evidence of external
                                                            corrosion whenever any
                                                            portion of a buried
                                                            pipeline is exposed.
Sec.   192.461..................  External corrosion       Records of protective         Life of pipeline.
                                   control: Protective      coating type, coating
                                   coating.                 installation and
                                                            procedures, surveys, and
                                                            remediation of coating
                                                            defects.
Sec.   192.465(a)...............  External corrosion       Records of pipe to soil       Life of pipeline.
                                   control: Monitoring.     measurements.
Sec.   192.465(b)...............  External corrosion       Records of rectifier          5 years.
                                   control: Monitoring--    inspections.
                                   rectifiers.
Sec.   192.465(c)...............  External corrosion       Records of inspections of     5 years.
                                   control: Monitoring--    each reverse current
                                   stray current/           switch, each diode, and
                                   interference             each interference bond
                                   mitigation and           whose failure would
                                   critical interference    jeopardize structure
                                   bonds.                   protection.
Sec.   192.465(e)...............  External corrosion       Records of re-evaluation of   Life of pipeline.
                                   control: Monitoring--    cathodically unprotected
                                   active corrosion zones.  pipelines.
Sec.   192.467(d)...............  External corrosion       Records of inspection and     Life of pipeline.
                                   control: Electrical      electrical tests made to
                                   isolation.               assure that electrical
                                                            isolation is adequate.
Sec.   192.473..................  External corrosion       Records of surveys,           Life of pipeline.
                                   control: Interference    analysis, and remediation
                                   currents.                of interference currents.
Sec.   192.475..................  Internal pipe            Records demonstrating         Life of pipeline.
                                   inspection.              whenever any pipe is
                                                            removed from a pipeline for
                                                            any reason, the internal
                                                            surface was inspected for
                                                            evidence of corrosion.
Sec.   192.476(d)...............  Internal corrosion       Records demonstrating         Life of pipeline.
                                   control: Design and      compliance with this
                                   construction of          section.
                                   transmission line.
Sec.   192.477..................  Coupons or other means   Records demonstrating the     Life of pipeline.
                                   for monitoring           effectiveness of each
                                   internal corrosion.      coupon or other means of
                                                            monitoring procedures used
                                                            to minimize internal
                                                            corrosion.
Sec.   192.478..................  Internal corrosion       Records demonstrating         Life of pipeline.
                                   control: Onshore         compliance with this
                                   transmission             section for internal
                                   monitoring and           monitoring and mitigation
                                   mitigation.              program.
Sec.   192.478(b)(3)............  Gas and Liquid Samples.  Records showing evaluation    Life of pipeline.
                                                            twice each calendar year of
                                                            gas stream and liquid
                                                            quality samples.
Sec.   192.481(a)...............  Atmospheric corrosion    Records of inspection of      5 years.
                                   control: Monitoring.     each pipeline or portion of
                                                            pipeline that is exposed to
                                                            the atmosphere for evidence
                                                            of atmospheric corrosion.
Sec.   192.485(c)...............  Remedial measures:       Pipe and material properties  Life of pipeline.
                                   Transmission lines.      used in remaining strength
                                                            calculations and remaining
                                                            strength calculations must
                                                            be documented in reliable,
                                                            traceable, verifiable, and
                                                            complete records.
Sec.   192.491(a) and (b).......  Corrosion control        Records or maps showing the   Life of pipeline.
                                   records.                 location of cathodically
                                                            protected piping, cathodic
                                                            protection facilities,
                                                            galvanic anodes, and
                                                            neighboring structures
                                                            bonded to the cathodic
                                                            protection system.
Sec.   192.491(c)...............  Corrosion control        Records of each test,         5 years.
                                   records.                 survey, or inspection
                                                            required by subpart I in
                                                            sufficient detail to
                                                            demonstrate the adequacy of
                                                            corrosion control measures
                                                            or that a corrosive
                                                            condition does not exist.
                                                           Records related to Sec.       Life of pipeline.
                                                            Sec.   192.465(a) and (e)
                                                            and 192.475(b) must be
                                                            retained for as long as the
                                                            pipeline remains in service.
----------------------------------------------------------------------------------------------------------------
                                          Subpart J--Test Requirements
----------------------------------------------------------------------------------------------------------------
Sec.   192.517(a)...............  Records................  Records of each test          Life of pipeline.
                                                            performed under Sec.  Sec.
                                                             192.505, 192.506, and
                                                            192.507.
Sec.   192.517(b)...............  Records................  Records of each test          5 years.
                                                            required by Sec.  Sec.
                                                            192.509, 192.511, and
                                                            192.513.
----------------------------------------------------------------------------------------------------------------

[[Page 20851]]

 
                                               Subpart K--Uprating
----------------------------------------------------------------------------------------------------------------
Sec.   192.553(b)...............  General requirements...  Records of each               Life of pipeline.
                                                            investigation required by
                                                            subpart K, of all work
                                                            performed, and of each
                                                            pressure test conducted, in
                                                            connection with uprating of
                                                            a segment of pipeline.
----------------------------------------------------------------------------------------------------------------
                                              Subpart L--Operations
----------------------------------------------------------------------------------------------------------------
Sec.   192.603(b)...............  General provisions.....  Records necessary to          Life of pipeline.
                                                            administer the procedures
                                                            established under Sec.
                                                            192.605 for operations,
                                                            maintenance, and
                                                            emergencies including class
                                                            location and changes in
                                                            Sec.  Sec.   192.5,
                                                            192.609, and 192.611.
Sec.   192.605..................  Procedural manual for    Records for O&M Manual--      5 years.
                                   operations,              review and update once per
                                   maintenance, and         calendar year, not to
                                   emergencies.             exceed 15 months.
Sec.   192.605..................  Procedural manual for    Records for Emergency Plan--  5 years.
                                   operations,              review and update once per
                                   maintenance, and         calendar year, not to
                                   emergencies.             exceed 15 months.
Sec.   192.605..................  Procedural manual for    Records for Operator          5 years.
                                   operations,              Qualification Plan--review
                                   maintenance, and         and update once per
                                   emergencies.             calendar year, not to
                                                            exceed 15 months.
Sec.   192.605(b)(12)...........  Procedural manual for    Records for Control Room      5 years.
                                   operations,              Management (CRM)--review
                                   maintenance, and         and update once per
                                   emergencies.             calendar year, not to
                                                            exceed 15 months.
Sec.   192.605(c)...............  Procedural manual for    For gas transmission          Life of pipeline.
                                   operations,              operators, a record of the
                                   maintenance, and         abnormal operations.
                                   emergencies.
Sec.   192.607(c)...............  Verification of          Traceable, verifiable, and    Life of pipeline.
                                   Pipeline Material:       complete records that
                                   Onshore steel            demonstrate and
                                   transmission pipelines.  authenticate data and
                                                            information regarding the
                                                            properties outlined in Sec.
                                                              192.607(c)(1) through (4).
Sec.   192.609..................  Change in class          Records for class location    Life of pipeline.
                                   location: Required       studies required by this
                                   study.                   section.
Sec.   192.611..................  Change in class          Records for revisions of      Life of pipeline.
                                   location: Confirmation   maximum allowable operating
                                   or revision of maximum   pressure due to class
                                   allowable operating      location changes to confirm
                                   pressure.                to Sec.   192.611.
Sec.   192.612..................  Underwater inspection    Records of Underwater         5 years.
                                   and reburial of          inspection in Gulf of
                                   pipelines in the Gulf    Mexico--periodic, as
                                   of Mexico and its        indicated in operators O&M
                                   inlets.                  Manual.
Sec.   192.613(a)...............  Continuing surveillance  Records of continuing         5 years.
                                                            surveillance findings.
Sec.   192.613(b)...............  Continuing surveillance  Records of remedial actions.  Life of pipeline.
Sec.   192.613(c)(1)............  Continuing surveillance  Records of inspections        5 years.
                                                            performed following extreme
                                                            events.
Sec.   192.613(c)(3)............  Continuing surveillance  Records of remedial actions.  Life of pipeline.
Sec.   192.614..................  Damage prevention        Damage Prevention/One Call    5 years (or as
                                   program.                 records.                      indicated by state one
                                                                                          call, whichever is
                                                                                          longer).
Sec.   192.614..................  Damage prevention        Records of Damage Prevention  5 years.
                                   program.                 meetings with Emergency
                                                            Responder/Public Officials.
Sec.   192.615..................  Emergency plans........  Records of training.........  5 years.
Sec.   192.615..................  Emergency plans........  Records of each review that   5 years.
                                                            procedures were effectively
                                                            followed after each
                                                            emergency.
Sec.   192.616..................  Public awareness.......  Records showing Public        5 years.
                                                            Education Activities.
Sec.   192.617..................  Investigation of         Procedures for analyzing      Life of pipeline.
                                   failures.                accidents and failures as
                                                            described in Sec.   192.617
                                                            to determine the causes of
                                                            the failure and minimizing
                                                            the possibility of a
                                                            recurrence. Records of
                                                            accident/failure reports.
Sec.   192.619..................  Maximum allowable        Traceable, verifiable, and    Life of pipeline.
                                   operating pressure:      complete records that
                                   Steel or plastic         demonstrate and
                                   pipelines.               authenticate data and
                                                            information regarding the
                                                            maximum allowable operating
                                                            pressures outlined in Sec.
                                                             192.619(a) through (d).
Sec.   192.620(c)(7)............  Alternative maximum      Records demonstrating         Life of pipeline.
                                   allowable operating      compliance with paragraphs
                                   pressure for certain     Sec.   192.620(b), (c)(6),
                                   steel pipelines.         and (d).
Sec.   192.624(f)...............  Maximum allowable        Reliable, traceable,          Life of pipeline.
                                   operating pressure       verifiable, and complete
                                   verification: Onshore    records of the
                                   steel transmission       investigations, tests,
                                   pipelines.               analyses, assessments,
                                                            repairs, replacements,
                                                            alterations, and other
                                                            actions made under the
                                                            requirements of Sec.
                                                            192.624.
Sec.   192.625..................  Odorization of gas.....  Records of Odorometer         5 years.
                                                            Readings--periodic, as
                                                            indicated in operators O&M
                                                            Manual.

[[Page 20852]]

 
Sec.   192.631(a)...............  Control room management  Records of control room       Life of pipeline.
                                                            management procedures that
                                                            implement the requirements
                                                            of this section.
Sec.   192.631(j)...............  Control room management  (1) Records that demonstrate  1 year, or the last 2
                                                            compliance with the           periodic tests or
                                                            requirements of this          validations, whichever
                                                            section; and.                 is longer.
                                                           (2) Documentation to
                                                            demonstrate that any
                                                            deviation from the
                                                            procedures required by this
                                                            section was necessary for
                                                            the safe operation of a
                                                            pipeline facility.
----------------------------------------------------------------------------------------------------------------
                                             Subpart M--Maintenance
----------------------------------------------------------------------------------------------------------------
Sec.   192.703(c)...............  General................  Records of hazardous and non- Life of pipeline.
                                                            hazardous leaks.
Sec.   192.705..................  Transmission lines:      Records of periodic right-of- 5 years.
                                   Patrolling.              way patrols--frequency
                                                            dependent on class location.
Sec.   192.706..................  Transmission lines:      Records of periodic leakage   5 years.
                                   Leakage surveys.         surveys--frequency
                                                            dependent on class location.
Sec.   192.709(a)...............  Transmission lines:      Records for the date,         Life of pipeline.
                                   Record keeping.          location, and description
                                                            of each repair made to pipe
                                                            (including pipe-to-pipe
                                                            connections).
Sec.   192.709(b) and (c).......  Transmission lines:      (b) Records of the date,      5 years.*
                                   Record keeping.          location, and description
                                                            of each repair made to
                                                            parts of the pipeline
                                                            system other than pipe must
                                                            be retained for at least 5
                                                            years.
                                                           (c) A record of each patrol,  .......................
                                                            survey, inspection, test,
                                                            and repair required by
                                                            subparts L and M of this
                                                            part must be retained for
                                                            at least 5 years or until
                                                            the next patrol, survey,
                                                            inspection, or test is
                                                            completed, whichever is
                                                            longer.*
Sec.   192.710..................  Pipeline assessments...  Records of pipeline           Life of pipeline.
                                                            assessments in class 3 or
                                                            class 4 locations and
                                                            moderate consequence area
                                                            as defined in Sec.   192.3
                                                            if the pipe segment can
                                                            accommodate inspection by
                                                            means of instrumented
                                                            inline inspection tools
                                                            (i.e., ``smart pigs'').
Sec.   192.713(c)...............  Transmission lines:      Records of each repair made   Life of pipeline.
                                   Permanent field repair   to transmission lines must
                                   of imperfections and     be documented.
                                   damages.
Sec.   192.713(d)...............  Transmission lines:      Repair and remediation        Life of pipeline.
                                   Permanent field repair   schedules, pressure
                                   of imperfections and     reductions and remaining
                                   damages.                 strength calculations must
                                                            be documented.
Sec.   192.731..................  Compressor stations:     Records of inspections and    5 years.
                                   Inspection and testing   tests of pressure relieving
                                   of relief devices.       and other remote control
                                                            shutdown devices.
Sec.   192.736..................  Compressor stations:     Records of inspections and    5 years.
                                   Gas detection.           tests of gas detection
                                                            systems--periodic, as
                                                            indicated in operators O&M
                                                            Manual.
Sec.   192.739..................  Pressure limiting and    Records of inspections and    5 years.
                                   regulating stations:     tests of pressure relief
                                   Inspection and testing.  devices and pressure
                                                            regulating stations and
                                                            equipment.
Sec.   192.743..................  Pressure limiting and    Records of capacity           5 years.
                                   regulating stations:     calculations or
                                   Capacity of relief       verifications for pressure
                                   devices.                 relief devices (except
                                                            rupture discs).
Sec.   192.745..................  Valve maintenance:       Records of inspections of     5 years.
                                   Transmission lines.      emergency valves.
Sec.   192.749..................  Vault maintenance......  Records of inspections of     5 years.
                                                            vaults containing pressure
                                                            regulating or pressure
                                                            limiting equipment.
----------------------------------------------------------------------------------------------------------------
                                 Subpart N--Qualification of Pipeline Personnel
----------------------------------------------------------------------------------------------------------------
Sec.   192.807..................  Operator qualification   Records that demonstrate      5 years.**
                                   recordkeeping.           compliance with subpart N
                                                            of this part Records
                                                            supporting an individual's
                                                            current qualification shall
                                                            be maintained while the
                                                            individual is performing
                                                            the covered task.**
                                                           Records of prior
                                                            qualification and records
                                                            of individuals no longer
                                                            performing covered tasks
                                                            shall be retained for a
                                                            period of five years..
----------------------------------------------------------------------------------------------------------------
                                Subpart O--Gas Transmission Integrity Management
----------------------------------------------------------------------------------------------------------------
Sec.   192.947..................  Integrity management...  Records that demonstrate      Life of pipeline.
                                                            compliance with all of the
                                                            requirements of subpart O
                                                            of this part.
----------------------------------------------------------------------------------------------------------------


[[Page 20853]]

0
50. Appendix D to part 192 is revised to read as follows:

Appendix D to Part 192--Criteria for Cathodic Protection and 
Determination of Measurements

    I. Criteria for cathodic protection--
    A. Steel, cast iron, and ductile iron structures.
    (1) A negative (cathodic) voltage across the structure 
electrolyte boundary of at least 0.85 volt, with reference to a 
saturated copper-copper sulfate reference electrode, often referred 
to as a half cell. Determination of this voltage must be made in 
accordance with sections II and IV of this appendix.
    (2) A minimum negative (cathodic) polarization voltage shift of 
100 millivolts. This polarization voltage shift must be determined 
in accordance with sections III and IV of this appendix.
    B. Aluminum structures.
    (1) Except as provided in paragraphs B(2) and (3) of this 
section, a minimum negative (cathodic) polarization voltage shift of 
100 millivolts. This polarization voltage shift must be determined 
in accordance with sections III and IV of this appendix.
    (2) Notwithstanding the minimum criteria in paragraph B(1) of 
this section, if aluminum is cathodically protected at voltages in 
excess of 1.20 volts as measured with reference to a copper-copper 
sulfate reference electrode, in accordance with section II of this 
appendix, the aluminum may suffer corrosion resulting from the 
build-up of alkali on the metal surface. A voltage in excess of 1.20 
volts may not be used unless previous test results indicate no 
appreciable corrosion will occur in the particular environment.
    (3) Since aluminum may suffer from corrosion under high pH 
conditions, and since application of cathodic protection tends to 
increase the pH at the metal surface, careful investigation or 
testing must be made before applying cathodic protection to stop 
pitting attack on aluminum structures in environments with a natural 
pH in excess of 8.
    C. Copper structures. A minimum negative (cathodic) polarization 
voltage shift of 100 millivolts. This polarization voltage shift 
must be determined in accordance with sections III and IV of this 
appendix.
    D. Metals of different anodic potentials. A negative (cathodic) 
voltage, measured in accordance with section IV of this appendix, 
equal to that required for the most anodic metal in the system must 
be maintained. If amphoteric structures are involved that could be 
damaged by high alkalinity covered by paragraphs B(2) and (3) of 
this section, they must be electrically isolated with insulating 
flanges, or the equivalent.
    II. Interpretation of voltage measurement. Structure-to-
electrolyte potential measurements must be made utilizing 
measurement techniques that will minimize voltage (IR) drops other 
than those across the structure electrolyte boundary. All voltage 
(IR) drops other than those across the structure electrolyte 
boundary will be differentiated, such that the resulting measurement 
accurately reflects the structure-to-electrolyte potential.
    III. Determination of polarization voltage shift. The 
polarization voltage shift must be determined by interrupting the 
protective current and measuring the polarization decay. When the 
current is initially interrupted, an immediate voltage shift occurs 
often referred to as an instant off potential. The voltage reading 
after the immediate shift must be used as the base reading from 
which to measure polarization decay in paragraphs A(2), B(1), and C 
of section I of this appendix.
    IV. Reference electrodes (half cells).
    A. Except as provided in paragraphs B and C of this section, 
negative (cathodic) voltage must be measured between the structure 
surface and a saturated copper-copper sulfate reference electrode 
contacting the electrolyte.
    B. Other standard reference electrodes may be substituted for 
the saturated copper-copper sulfate electrode. Two commonly used 
reference electrodes are listed below along with their voltage 
equivalent to -0.85 volt as referred to a saturated copper-copper 
sulfate reference electrode:
    (1) Saturated KCL calomel half cell:-0.78 volt.
    (2) Silver-silver chloride reference electrode used in sea 
water: -0.80 volt.
    C. In addition to the standard reference electrode, an alternate 
metallic material or structure may be used in place of the saturated 
copper-copper sulfate reference electrode if its potential stability 
is assured and if its voltage equivalent referred to a saturated 
copper-copper sulfate reference electrode is established.

0
51. In appendix E, Tables E.II.1 and E.II.3 are revised to read as 
follows:

Appendix E to Part 192--Guidance on Determining High Consequence Areas 
and on Carrying out Requirements in the Integrity Management Rule

* * * * *

II. Guidance on Assessment Methods and Additional Preventive and 
Mitigative Measures for Transmission Pipelines

* * * * *

 Table E.II.1--Preventive and Mitigative Measures for Transmission Pipelines Operating Below 30% SMYS not in an
                                    HCA but in a Class 3 or Class 4 Location
----------------------------------------------------------------------------------------------------------------
                                             Existing part 192 requirements           (Column 4)  Additional (to
                                    ------------------------------------------------    part 192 requirements)
         (Column 1) Threat                                                            preventive and mitigative
                                       (Column 2)  Primary    (Column 3)  Secondary            measures
----------------------------------------------------------------------------------------------------------------
External Corrosion.................  455--(Gen. Post 1971),  603--(Gen Operation)..  For Cathodically Protected
                                      457--(Gen. Pre--1971).                          Transmission Pipeline:
                                     459--(Examination),     613--(Surveillance)...   Perform semi-
                                      461--(Ext. coating).                            annual leak surveys.
                                     463--(CP), 465--        ......................  For Unprotected
                                      (Monitoring).                                   Transmission Pipelines or
                                                                                      for Cathodically Protected
                                                                                      Pipe where indirect
                                                                                      assessments (i.e.,
                                                                                      indirect examination tool/
                                                                                      method such as close
                                                                                      interval survey,
                                                                                      alternating current
                                                                                      voltage gradient, direct
                                                                                      current voltage gradient,
                                                                                      or equivalent) are
                                                                                      impractical:
                                     467--(Elect
                                      isolation), 469--Test
                                      stations).
                                     471--(Test leads),
                                      473--(Interference).
                                     479--(Atmospheric),
                                      481--(Atmospheric).
                                     485--(Remedial), 705--
                                      (Patrol).
                                     706-- (Leak survey),
                                      711--(Repair--gen.).
                                     717--(Repair--perm.)..  ......................   Perform quarterly
                                                                                      leak surveys.
Internal Corrosion.................  475--(Gen IC), 477--    53(a)--(Materials)....  Perform semi-annual leak
                                      (IC monitoring).                                surveys.

[[Page 20854]]

 
                                     485--(Remedial), 705--  603--(Gen Oper'n).....
                                      (Patrol).
                                     706--(Leak survey),     613--(Surveillance)...
                                      711 (Repair--gen.).
                                     717--(Repair--perm.)..
3rd Party Damage...................  103--(Gen. Design),     ......................   Participation in
                                      111--(Design factor).                           state one-call system.
                                     317--(Hazard prot),     615--(Emerg. Plan)....   Use of qualified
                                      327--(Cover).                                   operator employees and
                                                                                      contractors to perform
                                                                                      marking and locating of
                                                                                      buried structures and in
                                                                                      direct supervision of
                                                                                      excavation work.
                                     614--(Dam. Prevent),    ......................  AND
                                      616--(Public
                                      education).
                                     705--(Patrol), 707--                             Either monitoring
                                      (Line markers).                                 of excavations near
                                                                                      operator's transmission
                                                                                      pipelines in class 3 and 4
                                                                                      locations. Any indications
                                                                                      of unreported construction
                                                                                      activity would require a
                                                                                      follow up investigation to
                                                                                      determine if mechanical
                                                                                      damage occurred.
                                     711--(Repair--gen.),
                                      717--(Repair--perm.).
----------------------------------------------------------------------------------------------------------------

* * * * *

     Table E.II.3--Preventive and Mitigative Measures Addressing Time Dependent and Independent Threats for
                           Transmission Pipelines That Operate Below 30% SMYS, in HCAs
----------------------------------------------------------------------------------------------------------------
                                           Existing part 192 requirements             Additional (to part 192
              Threat               ----------------------------------------------  requirements)  preventive and
                                           Primary               Secondary              mitigative measures
----------------------------------------------------------------------------------------------------------------
External Corrosion................  455--(Gen. Post 1971)  .....................  For Cathodically Protected
                                                                                   Transmission Pipelines
                                    457--(Gen. Pre-1971).  .....................   Perform an indirect
                                                                                   assessment (i.e. indirect
                                                                                   examination tool/method such
                                                                                   as close interval survey,
                                                                                   alternating current voltage
                                                                                   gradient, direct current
                                                                                   voltage gradient, or
                                                                                   equivalent) at least every 7
                                                                                   years. Results are to be
                                                                                   utilized as part of an
                                                                                   overall evaluation of the CP
                                                                                   system and corrosion threat
                                                                                   for the covered segment.
                                                                                   Evaluation shall include
                                                                                   consideration of leak repair
                                                                                   and inspection records,
                                                                                   corrosion monitoring records,
                                                                                   exposed pipe inspection
                                                                                   records, and the pipeline
                                                                                   environment.
                                    459--(Examination)...
                                    461--(Ext. coating)..
                                    463--(CP)............
                                    465--(Monitoring)....  603--(Gen. Operation)
                                    467--(Elect            613--(Surveillance)..
                                     isolation).
                                    469--(Test stations).
                                    471--(Test leads)....  .....................  For Unprotected Transmission.
                                                                                   Pipelines or for Cathodically
                                                                                   Protected Pipe where Indirect
                                                                                   Assessments are Impracticable
                                    473--(Interference)..
                                    479--(Atmospheric)...  .....................   Conduct quarterly
                                                                                   leak surveys AND
                                    481--(Atmospheric)...  .....................   Every 1\1/2\ years,
                                                                                   determine areas of active
                                                                                   corrosion by evaluation of
                                                                                   leak repair and inspection
                                                                                   records, corrosion monitoring
                                                                                   records, exposed pipe
                                                                                   inspection records, and the
                                                                                   pipeline environment.
                                    485--(Remedial)......
                                    705--(Patrol)........
                                    706--(Leak survey)...
                                    711--(Repair--gen.)..
                                    717--(Repair--perm.).
Internal Corrosion................  475--(Gen. IC).......  .....................   Obtain and review gas
                                                                                   analysis data each calendar
                                                                                   year for corrosive agents
                                                                                   from transmission pipelines
                                                                                   in HCA,
                                    477--(IC monitoring).  .....................   Periodic testing of
                                                                                   fluid removed from pipelines.
                                                                                   Specifically, once each year
                                                                                   from each storage field that
                                                                                   may affect transmission
                                                                                   pipelines in HCA, AND
                                    485--(Remedial)......  53(a)--(Materials)...   At least every 7
                                                                                   years, integrate data
                                                                                   obtained with applicable
                                                                                   internal corrosion leak
                                                                                   records, incident reports,
                                                                                   safety related condition
                                                                                   reports, repair records,
                                                                                   patrol records, exposed pipe
                                                                                   reports, and test records.
                                    705--(Patrol)........  603--(Gen. Oper.)....
                                    706--(Leak survey)...  613--(Surveil.)......
                                    711--(Repair--gen.)..

[[Page 20855]]

 
                                    717--(Repair--perm.).
3rd Party Damage..................  103--(Gen. Design)...  615-- (Emerg. Plan)..   Participation in
                                                                                   state one-call system,
                                    111--(Design factor).  .....................   Use of qualified
                                                                                   operator employees and
                                                                                   contractors to perform
                                                                                   marking and locating of
                                                                                   buried structures and in
                                                                                   direct supervision of
                                                                                   excavation work, AND
                                    317--(Hazard prot.)..  .....................   Either monitoring of
                                                                                   excavations near operator's
                                                                                   transmission pipelines, or bi-
                                                                                   monthly patrol of
                                                                                   transmission pipelines in
                                                                                   HCAs or class 3 and 4
                                                                                   locations. Any indications of
                                                                                   unreported construction
                                                                                   activity would require a
                                                                                   follow up investigation to
                                                                                   determine if mechanical
                                                                                   damage occurred.
                                    327--(Cover).........
                                    614--(Dam. Prevent)..
                                    616--(Public educat.)
                                    705--(Patrol)........
                                    707--(Line markers)..
                                    711--(Repair--gen.)..
                                    717--(Repair--perm.).
----------------------------------------------------------------------------------------------------------------

0
52. Appendix F to part 192 is added to read as follows:

Appendix F to Part 192--Criteria for Conducting Integrity Assessments 
Using Guided Wave Ultrasonic Testing (GWUT)

    This appendix defines criteria which must be properly 
implemented for use of Guided Wave Ultrasonic Testing (GWUT) as an 
integrity assessment method. Any application of GWUT that does not 
conform to these criteria is considered ``other technology'' as 
described by Sec. Sec.  192.710(c)(7), 192.921(a)(7), and 
192.937(c)(7), for which OPS must be notified 180 days prior to use 
in accordance with Sec.  192.921(a)(7) or 192.937(c)(7). GWUT in the 
``Go-No Go'' mode means that all indications (wall loss anomalies) 
above the testing threshold (a maximum of 5% of cross sectional area 
(CSA) sensitivity) be directly examined, in-line tool inspected, 
pressure tested or replaced prior to completing the integrity 
assessment on the cased carrier pipe.
    I. Equipment and software: Generation. The equipment and the 
computer software used are critical to the success of the 
inspection. Guided Ultrasonics LTD (GUL) Wavemaker G3 or G4 with 
software version 3 or higher, or equipment and software with 
equivalent capabilities and sensitivities, must be used.
    II. Inspection range. The inspection range and sensitivity are 
set by the signal to noise (S/N) ratio but must still keep the 
maximum threshold sensitivity at 5% cross sectional area (CSA). A 
signal that has an amplitude that is at least twice the noise level 
can be reliably interpreted. The greater the S/N ratio the easier it 
is to identify and interpret signals from small changes. The signal 
to noise ratio is dependent on several variables such as surface 
roughness, coating, coating condition, associated pipe fittings 
(T's, elbows, flanges), soil compaction, and environment. Each of 
these affects the propagation of sound waves and influences the 
range of the test. It may be necessary to inspect from both ends of 
the pipeline segment to achieve a full inspection. In general the 
inspection range can approach 60 to 100 feet for a 5% CSA, depending 
on field conditions.
    III. Complete pipe inspection. To ensure that the entire 
pipeline segment is assessed there should be at least a 2 to 1 
signal to noise ratio across the entire pipeline segment that is 
inspected. This may require multiple GWUT shots. Double ended 
inspections are expected. These two inspections are to be overlaid 
to show the minimum 2 to 1 S/N ratio is met in the middle. If 
possible, show the same near or midpoint feature from both sides and 
show an approximate 5% distance overlap.
    IV. Sensitivity.
    A. The detection sensitivity threshold determines the ability to 
identify a cross sectional change. The maximum threshold sensitivity 
cannot be greater than 5% of the cross sectional area (CSA).
    B. The locations and estimated CSA of all metal loss features in 
excess of the detection threshold must be determined and documented.
    C. All defect indications in the ``Go-No Go'' mode above the 5% 
testing threshold must be directly examined, in-line inspected, 
pressure tested, or replaced prior to completing the integrity 
assessment.
    V. Wave frequency. Because a single wave frequency may not 
detect certain defects, a minimum of three frequencies must be run 
for each inspection to determine the best frequency for 
characterizing indications. The frequencies used for the inspections 
must be documented and must be in the range specified by the 
manufacturer of the equipment.
    VI. Signal or wave type: Torsional and longitudinal. Both 
torsional and longitudinal waves must be used and use must be 
documented.
    VII. Distance amplitude correction (DAC) curve and weld 
calibration.
    A. The Distance Amplitude Correction curve accounts for coating, 
pipe diameter, pipe wall and environmental conditions at the 
assessment location. The DAC curve must be set for each inspection 
as part of establishing the effective range of a GWUT inspection.
    B. DAC curves provide a means for evaluating the cross sectional 
area change of reflections at various distances in the test range by 
assessing signal to noise ratio. A DAC curve is a means of taking 
apparent attenuation into account along the time base of a test 
signal. It is a line of equal sensitivity along the trace which 
allows the amplitudes of signals at different axial distances from 
the collar to be compared.
    VIII. Dead zone. The dead zone is the area adjacent to the 
collar in which the transmitted signal blinds the received signal, 
making it impossible to obtain reliable results. Because the entire 
line must be inspected, inspection procedures must account for the 
dead zone by requiring the movement of the collar for additional 
inspections. An alternate method of obtaining valid readings in the 
dead zone is to use B-scan ultrasonic equipment and visual 
examination of the external surface. The length of the dead zone and 
the near field for each inspection must be documented.
    IX. Near field effects. The near field is the region beyond the 
dead zone where the receiving amplifiers are increasing in power, 
before the wave is properly established. Because the entire line 
must be inspected, inspection procedures must account for the near 
field by requiring the movement of the collar for additional 
inspections. An alternate method of obtaining valid readings in the 
near field is to use B-scan ultrasonic equipment and visual 
examination of the external surface. The length of the dead zone and 
the near field for each inspection must be documented.
    X. Coating type.
    A. Coatings can have the effect of attenuating the signal. Their 
thickness and condition are the primary factors that affect the rate 
of signal attenuation. Due to their variability, coatings make it 
difficult to predict the effective inspection distance.
    B. Several coating types may affect the GWUT results to the 
point that they may reduce the expected inspection distance. For

[[Page 20856]]

example, concrete coated pipe may be problematic when well bonded 
due to the attenuation effects. If an inspection is done and the 
required sensitivity is not achieved for the entire length of the 
cased pipe, then another type of assessment method must be utilized.
    XI. End seal. Operators must remove the end seal from the casing 
at each GWUT test location to facilitate visual inspection. 
Operators must remove debris and water from the casing at the end 
seals. Any corrosion material observed must be removed, collected 
and reviewed by the operator's corrosion technician. The end seal 
does not interfere with the accuracy of the GWUT inspection but may 
have a dampening effect on the range.
    XII. Weld calibration to set DAC curve. Accessible welds, along 
or outside the pipe segment to be inspected, must be used to set the 
DAC curve. A weld or welds in the access hole (secondary area) may 
be used if welds along the pipe segment are not accessible. In order 
to use these welds in the secondary area, sufficient distance must 
be allowed to account for the dead zone and near field. There must 
not be a weld between the transducer collar and the calibration 
weld. A conservative estimate of the predicted amplitude for the 
weld is 25% CSA (cross sectional area) and can be used if welds are 
not accessible. Calibrations (setting of the DAC curve) should be on 
pipe with similar properties such as wall thickness and coating. If 
the actual weld cap height is different from the assumed weld cap 
height, the estimated CSA may be inaccurate and adjustments to the 
DAC curve may be required. Alternative means of calibration can be 
used if justified by sound engineering analysis and evaluation.
    XIII. Validation of operator training.
    A. There is no industry standard for qualifying GWUT service 
providers. Pipeline operators must require all guided wave service 
providers to have equipment-specific training and experience for all 
GWUT equipment operators which includes training for:
    (1) Equipment operation;
    (2) Field data collection; and
    (3) Data interpretation on cased and buried pipe.
    B. Only individuals who have been qualified by the manufacturer 
or an independently assessed evaluation procedure similar to ISO 
9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7 
Eligibility; and 10 Certification), as specified above, may operate 
the equipment.
    C. A Senior level GWUT equipment operator with pipeline specific 
experience must provide onsite oversight of the inspection and 
approve the final reports. A senior level GWUT equipment operator 
must have additional training and experience, including but not 
limited to training specific to cased and buried pipe, with a 
quality control program which conforms to section 12 of ASME B31.8S.
    D. Training and experience minimums for senior level GWUT 
equipment operators:
    (1) Equipment Manufacturer's minimum qualification for equipment 
operation and data collection with specific endorsements for casings 
and buried pipe
    (2) Training, qualification and experience in testing procedures 
and frequency determination
    (3) Training, qualification and experience in conversion of 
guided wave data into pipe features and estimated metal loss 
(estimated cross-sectional area loss and circumferential extent)
    (4) Equipment Manufacturer's minimum qualification with specific 
endorsements for data interpretation of anomaly features for pipe 
within casings and buried pipe.
    XIV. Equipment: Traceable from vendor to inspection company. The 
operator must maintain documentation of the version of the GWUT 
software used and the serial number of the other equipment such as 
collars, cables, etc., in the report.
    XV. Calibration onsite. The GWUT equipment must be calibrated 
for performance in accordance with the manufacturer's requirements 
and specifications, including the frequency of calibrations. A 
diagnostic check and system check must be performed on-site each 
time the equipment is relocated. If on-site diagnostics show a 
discrepancy with the manufacturer's requirements and specifications, 
testing must cease until the equipment can be restored to 
manufacturer's specifications.
    XVI. Use on shorted casings (direct or electrolytic). GWUT may 
not be used to assess shorted casings. GWUT operators must have 
operations and maintenance procedures (see Sec.  192.605) to address 
the effect of shorted casings on the GWUT signal. The equipment 
operator must clear any evidence of interference, other than some 
slight dampening of the GWUT signal from the shorted casing, 
according to their operating and maintenance procedures. All shorted 
casings found while conducting GWUT inspections must be addressed by 
the operator's standard operating procedures.
    XVII. Direct examination of all indications above the detection 
sensitivity threshold.
    The use of GWUT in the ``Go-No Go'' mode requires that all 
indications (wall loss anomalies) above the testing threshold (5% of 
CSA sensitivity) be directly examined (or replaced) prior to 
completing the integrity assessment on the cased carrier pipe. If 
this cannot be accomplished then alternative methods of assessment 
(such as hydrostatic pressure tests or ILI) must be utilized.
    XVIII. Timing of direct examination of all indications above the 
detection sensitivity threshold. Operators must either replace or 
conduct direct examinations of all indications identified above the 
detection sensitivity threshold according to the table below. 
Operators must conduct leak surveys and reduce operating pressure as 
specified until the pipe is replaced or direct examinations are 
completed.

----------------------------------------------------------------------------------------------------------------
                                      Required response to GWUT indications
-----------------------------------------------------------------------------------------------------------------
                                      Operating pressure   Operating pressure over 30
          GWUT Criterion            less than or equal to   and less than or equal to   Operating pressure over
                                           30% SMYS                 50% SMYS                    50% SMYS
----------------------------------------------------------------------------------------------------------------
Over the detection sensitivity      Replace or direct      Replace or direct           Replace or direct
 threshold (maximum of 5% CSA).      examination within     examination within 6        examination within 6
                                     12 months, and         months, instrumented leak   months, instrumented
                                     instrumented leak      survey once every 30        leak survey once every
                                     survey once every 30   calendar days, and          30 calendar days, and
                                     calendar days.         maintain MAOP below the     reduce MAOP to 80% of
                                                            operating pressure at       operating pressure at
                                                            time of discovery.          time of discovery.
----------------------------------------------------------------------------------------------------------------



    Issued in Washington, DC, on March 17, 2016, under authority 
delegated in 49 CFR part 1.97(a).
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2016-06382 Filed 4-7-16; 8:45 am]
 BILLING CODE 4910-60-P


