[Federal Register: October 17, 2008 (Volume 73, Number 202)]
[Rules and Regulations]
[Page 62147-62181]
[DOCID:fr17oc08-16]

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Part V

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Part 192

 Pipeline Safety: Standards for Increasing the Maximum Allowable
Operating Pressure for Gas Transmission Pipelines; Final Rule

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-2005-23447]
RIN 2137-AE25

Pipeline Safety: Standards for Increasing the Maximum Allowable
Operating Pressure for Gas Transmission Pipelines

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

ACTION: Final rule.

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SUMMARY: PHMSA is amending the pipeline safety regulations to prescribe
safety requirements for the operation of certain gas transmission
pipelines at pressures based on higher operating stress levels. The
result is an increase of maximum allowable operating pressure (MAOP)
over that currently allowed in the regulations. Improvements in
pipeline technology assessment methodology, maintenance practices, and
management processes over the past twenty-five years have significantly
reduced the risk of failure in pipelines and necessitate updating the
standards that govern the MAOP. This rule will generate significant
public benefits by reducing the number and consequences of potential
incidents and boosting the potential capacity and efficiency of
pipeline infrastructure, while promoting rigorous life-cycle
maintenance and investment in improved pipe technology.

DATES: Effective Date: This final rule takes effect November 17, 2008.
    Incorporation by Reference Date: The incorporation by reference of
a certain publication listed in this rule is approved by the Director
of the Federal Register as of November 17, 2008.

FOR FURTHER INFORMATION CONTACT: Alan Mayberry by phone at (202) 366-
5124, or by e-mail at<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

A. Purpose of the Rulemaking
B. Background
    B.1. Current Regulations
    B.2. Evolution in Views on Pressure
    B.3. History of PHMSA Consideration
    B.4. Safety Conditions in Special Permits
    B.5. Codifying the Special Permit Standards
    B.6. How to Handle Special Permits and Requests for Special
Permits
    B.7. Statutory Considerations
C. Comments on the NPRM
    C.1. General Comments
    C.2. Comments on Specific Provisions in the Proposed Rule
    C.2.1. Section 192.7, Incorporation by Reference
    C.2.2. Design Requirements
    C.2.3. Construction Requirements
    C.2.4. Eligibility for and Implementing Alternative MAOP
    C.2.5. Operation and Maintenance Requirements
    C.3. Comments on Regulatory Analysis
D. Consideration by the Technical Pipeline Safety Standards
Committee
E. The Final Rule
    E.1. In General
    E.2. Amendment to Sec.  192.7--Incorporation by Reference
    E.3. New Sec.  192.112--Additional Design Requirements
    E.4. New Sec.  192.328--Additional Construction Requirements
    E.5. Amendment to Sec.  192.611--Change in Class Location:
Confirmation or Revision of Maximum Operating Pressure
    E.6. Amendment to Sec.  192.619--Maximum Allowable Operating
Pressure
    E.7. New Sec.  192.620--Operation at an Alternative MAOP
    E.7.1. Sec.  192.620(a)--Calculating the Alternative MAOP
    E.7.2. Sec.  192.620(b)--Which Pipelines Qualify
    E.7.3. Sec. Sec.  192.620(c)(1), (2), and (3)--How an Operator
Selects Operation Under This Section
    E.7.4. Sec.  192.620(c)(4)--Initial Strength Testing
    E.7.5. Sec.  192.620(c)(5)--Operation and Maintenance
    E.7.6. Sec.  192.620(c)(6)--New Construction and Maintenance
Tasks
    E.7.7. Sec.  192.620(c)(7)--Recordkeeping
    E.7.8. Sec.  192.620(c)(8)--Class Upgrades
    E.8. Sec.  192.620(d)--Additional Operation and Maintenance
Requirements
    E.8.1. Sec.  192.620(d)(1)--Threat Assessments
    E.8.2. Sec.  192.620(d)(1)--Public Awareness
    E.8.3. Sec.  192.620(d)(2)--Emergency Response
    E.8.4. Sec.  192.620(d)(3)--Damage Prevention
    E.8.5. Sec.  192.620(d)(4)--Internal Corrosion Control
    E.8.6. Sec. Sec.  192.620(d)(5), (6), and (7)--External
Corrosion Control
    E.8.7. Sec. Sec.  192.620(d)(8) and (9)--Integrity Assessments
    E.8.8. Sec.  192.620(d)(10)--Repair Criteria
    E.9. Sec.  192.620(e)--Overpressure Protection--Proposed Sec.
192.620(e)
F. Regulatory Analyses and Notices
    F.1. Privacy Act Statement
    F.2. Executive Order 12866 and DOT Policies and Procedures
    F.3. Regulatory Flexibility Act
    F.4. Executive Order 13175
    F.5. Paperwork Reduction Act
    F.6. Unfunded Mandates Reform Act of 1995
    F.7. National Environmental Policy Act
    F.8. Executive Order 13132
    F.9. Executive Order 13211

A. Purpose of the Rulemaking

    PHMSA published a Notice of Proposed Rulemaking (NPRM) on March 12,
2008 (73 FR 13167), to establish standards under which certain natural
or other gas (gas) transmission pipelines would be allowed to operate
at higher maximum allowable operating pressure (MAOP). The proposed
changes were made possible by dramatic improvements in pipeline
technology and risk controls over the past 25 years. The current
standards for calculating MAOP on gas transmission pipelines were
adopted in 1970, in the original pipeline safety regulations
promulgated under Federal law. Almost all risk controls on gas
transmission pipelines have been strengthened in the intervening years,
beginning with the introduction of improved manufacturing, metallurgy,
testing, and assessment tools and standards. Pipe manufactured and
tested to modern standards is far less likely to contain defects that
can grow to failure over time than pipe manufactured and installed a
generation ago. Likewise, modern maintenance practices, if consistently
followed, significantly reduce the risk that corrosion, or other
defects affecting pipeline integrity, will develop in installed
pipelines. Most recently, operators' development and implementation of
integrity management programs have increased understanding about the
condition of pipelines and how to reduce pipeline risks. In view of
these developments, PHMSA concludes that certain gas transmission
pipelines can be safely and reliably operated at pressures above
current Federal pipeline safety design limits. With appropriate
conditions and controls, permitting operation at higher pressures will
increase energy capacity and efficiency without diminishing system
safety.
    Currently, PHMSA has granted special permits on a case-by-case
basis to allow operation of particular pipeline segments at a higher
MAOP than currently allowed under the existing design requirements.
These special permits, that have been granted, have been limited to
operation in Class 1, 2, and 3 locations and conditioned on
demonstrated rigor in the pipeline's design and construction and the
operator's performance of additional safety measures. Building on the
record of success developed in the special permit proceedings, PHMSA is
codifying the conditions and limitations of the special permits into
standards of general applicability.

B. Background

B.1. Current Regulations

    The design factor specified in Sec.  192.105 restricts the MAOP of
a steel

gas transmission pipeline based on stress levels and class location.
For most steel pipelines, the MAOP is defined in Sec.  192.619 based on
design pressure calculated using a formula, found at Sec.  192.111,
which includes the design factor. The regulations establish four
classifications based on population density, ranging from Class 1
(undeveloped, rural land) through Class 4 (densely populated urban
areas). In sparsely populated Class 1 locations, the design factor
specified in Sec.  192.105 restricts the stress level at which a
pipeline can be operated to 72 percent of the specified minimum yield
strength (SMYS) of the steel. The operating pressures in more populated
Class 2 and Class 3 locations are limited to 60 and 50 percent of SMYS,
respectively. Paragraph (c) of Sec.  192.619 provides an exception to
this calculation of MAOP for pipelines built before the issuance of the
Federal pipeline safety standards. A pipeline that is ``grandfathered''
under this section may be operated at a stress level exceeding 72
percent of SMYS if it was operated at that pressure for five years
prior to July 1, 1970.
    Part 192 also prescribes safety standards for designing,
constructing, operating, and maintaining steel pipelines used to
transport gas. Although these standards have always included several
requirements for initial and periodic testing and inspection, prior to
2003, part 192 contained no Federal requirements for internal
inspection of existing pipelines. Internal inspection is performed
using a tool known as an ``instrumented pig'' (or ``smart pig''). Many
pipelines constructed before the advent of this technology cannot
accommodate an instrumented pig and, accordingly, cannot be inspected
internally. Beginning in 1994, PHMSA required operators to design new
pipelines so that they could accommodate instrumented pigs, paving the
way for internal inspection (59 FR 17281; Apr. 12, 1994).
    In December 2003, PHMSA adopted its gas transmission integrity
management rule, requiring operators to develop and implement plans to
extend additional protections, including internal inspection, to
pipelines located in ``high consequence areas'' (HCAs) (68 FR 69816).
Integrity management programs, as required by subpart O of part 192,
include threat assessments, both baseline and periodic internal
inspection, pressure testing, or direct assessment (DA), and additional
measures designed to prevent and mitigate pipeline failures and their
consequences. AN HCA, as defined in Sec.  192.903, is a geographic
territory in which, by virtue of its population density and proximity
to a pipeline, a pipeline failure would pose a higher risk to people.
In addition to class location, one of the criteria for identifying an
HCA is a potential impact circle surrounding a pipeline. The
calculation of the circle includes a factor for the MAOP, with the
result that a higher MAOP results in a larger impact circle.

B.2. Evolution in Views on Pressure

    Absent any defects, and with proper maintenance and management
practices, steel pipe can last for many decades in gas service.
However, the manufacture of the steel or rolling of the pipe can
introduce flaws. In addition, during construction, improper backfilling
can damage the pipe and pipe coating. Over time, damaged coating
unchecked can allow corrosion to continue and cause leaks. Excavation-
related damage can produce an immediate pipeline failure or leave a
dent or coating damage that could grow to failure over time.
    The regulations on MAOP in part 192 have their origin in
engineering standards developed in the 1950s, when industry had
relatively limited information about the material properties of pipe
and limited ability to evaluate a pipeline's integrity during its
operating lifetime. Early pipeline codes allowed maximum operating
pressures to be set at a fixed amount under the pressure of the initial
strength test without regard to SMYS. Pipeline engineers developing
consensus standards looked for ways to lengthen the time before defects
initiated during manufacture, construction, or operation could grow to
failure. Their solutions focused on tests done at the mill to evaluate
the ability of the pipe to contain pressure during operation. They
added an additional factor to the hydrostatic test pressure of the mill
test. At the time during the 1950's, the consensus standard, known as
the B31.8 Code, used this conservative margin of safety for gas pipe
design. A 25 percent margin of safety translated into a design factor
limiting stress level to 72 percent of SMYS in rural areas.
Specifically, the MAOP of 72 percent of SMYS comes from dividing the
typical maximum mill test pressure of 90 percent of SMYS by 1.25. When
issuing the first Federal pipeline safety regulations in 1970,
regulators incorporated this design factor, as found in the 1968
edition of the B31.8 Code, into the requirements for determining the
MAOP.
    Even as the Federal regulations were being developed, some
technical support existed for operation at a higher stress level,
provided initial strength testing resulted in operators removing
defects. In 1968, the American Gas Association published Report No.
L30050 entitled Study of Feasibility of Basing Natural Gas Pipeline
Operating Pressure on Hydrostatic Test Pressure prepared by the
Battelle Memorial Institute. The research study concluded that:
     It is inherently safer to base the MAOP on the test
pressure, which demonstrates the actual in-place yield strength of the
pipeline, than to base it on SMYS alone.
     High pressure hydrostatic testing is able to remove
defects that may fail in service.
     Hydrostatic testing to actual yield, as determined with a
pressure-volume plot, does not damage a pipeline.
    The report specifically recommended setting the MAOP as a
percentage of the field test pressure. In particular, it recommended
setting the MAOP at 80 percent of the test pressure when the minimum
test pressure was 90 percent of SMYS or higher. Although the committee
responsible for the B31.8 Code received the report, the committee
deferred consideration of its findings at that time because the Federal
regulators had already begun the process to incorporate the 1968
edition of the B31.8 Code into the Federal pipeline safety standards.
    More than a decade later, the committee responsible for development
of the B31.8 Code, now under the auspices of the American Society of
Mechanical Engineers (ASME), revisited the question of the design
factor it had deferred in the late 1960s. The committee determined
pipelines could operate safely at stress levels up to 80 percent of
SMYS. ASME updated the design factors in a 1990 addendum to the 1989
edition of the B31.8 Code, and they remain in the current edition.
Although part 192 incorporates parts of the B31.8 Code by reference, it
does not incorporate the updated design factors. With the benefit of
operating experience with pipelines, it seems clear that operating
pressure plays a less critical role in pipeline integrity and failure
consequence than other factors within the operator's control.
    By any measure, new technologies and risk controls have had a far
greater impact on pipeline safety and integrity. A great deal of
progress has occurred in the manufacture of steel pipe and in its
initial inspection and testing. Technological advances in metallurgy
and pipe manufacture decrease the risk of incipient flaws occurring and
going undetected during manufacture. The detailed standards now
followed in steel and pipe manufacturing provide

engineers considerable information about their material properties.
Toughness standards make new steel pipe more likely to resist fracture
and to survive mechanical damage. Knowledge about the material
properties allows engineers to predict how quickly flaws, whether
inherent or introduced during construction or operation, will grow to
failure under known operating conditions.
    Initial inspection and hydrostatic testing of pipelines allow
operators to discover flaws that have occurred prior to operation, such
as during transportation or construction. They also serve to validate
the integrity of the pipeline before operation. Initial pressure
testing causes longitudinal and some other flaws introduced during
manufacture, transportation, or construction to grow to the point of
failure. Initial pressure testing detects all but one type of
manufacturing or construction defect that could cause failure in the
near-term. The sole type of defect that pressure testing may not
identify, a flaw in a girth weld, is detectable through pre-operational
non-destructive testing, which is required in this rule.
    The most common defects initiated during operation are caused by
mechanical damage or corrosion. Improvements in technology have
resulted in internal inspection techniques that provide operators a
significant amount of information about defects. Although there is
significant variance in the capability of the tools used for internal
inspections, each provides the operator information about flaws in the
pipeline that an operator would not otherwise have. An operator can
then examine these flaws to determine whether they are defects
requiring repair. In addition, internal inspections with in-line
inspection (ILI) devices, unlike pressure testing, are not destructive
and can be done while the pipeline is in operation. Initial internal
inspection establishes a baseline. Operators can use subsequent
internal inspections at appropriate intervals to monitor for changes in
flaws already discovered or to find new flaws requiring repair or
monitoring. Internal inspections, and other improved life-cycle
management practices, increase the likelihood operators will detect any
flaws that remain in the pipe after initial inspection and testing, or
that develop after construction, well before the flaws grow to failure.

B.3. History of PHMSA Consideration

    Although the agency had never formally revisited its part 192 MAOP
standards, prior to this rulemaking, developments in related arenas
have increasingly set the stage for changes to those standards.
Grandfathered pipelines have operated successfully at higher stress
levels in the United States during more than 35 years of Federal safety
regulation. Many of these grandfathered pipelines have operated at
higher stress levels for more than 50 years without a higher rate of
failure. We have also been aware of pipelines outside the United States
operating successfully at the higher stress levels permitted under the
ASME standard. A technical study published in December 2000 by R.J.
Eiber, M. McLamb, and W.B. McGehee, Quantifying Pipeline Design at 72%
SMYS as a Precursor to Increasing the Design Stress Level, GRI-00/0233,
further raised interest in the issue.
    In connection with our issuance of the 2003 gas transmission
integrity management regulations, PHMSA announced a policy to grant
``class location'' waivers (now called special permits) to operators
demonstrating an alternative integrity management program for the
affected pipeline. A ``class location'' waiver allows an operator to
maintain current operating pressure on a pipeline following an increase
in population that changes the class location. Absent a waiver, the
operator would have to reduce pressure or replace the pipe with thicker
walled pipe. PHMSA held a meeting on April 14-15, 2004, to discuss the
criteria for the waivers. In a notice seeking public involvement in the
process (69 FR 22116; Apr. 23, 2004), PHMSA announced:

    Waivers will only be granted when pipe condition and active
integrity management provides a level of safety greater than or
equal to a pipe replacement or pressure reduction.

    A second notice (69 FR 38948; June 29, 2004) announced the
criteria. The criteria included the use of high quality manufacturing
and construction processes, effective coating, and a lack of systemic
problems identified in internal inspections Although the class location
special permits/waivers do not address increases in stress levels per
se, the risk management approach developed in those cases takes account
of operating pressure and addresses many of the same concerns. The same
risk management approach, and many of the specific criteria applied in
the class location waivers, guided PHMSA's handling of the special
permits discussed below and, ultimately, this rule.
    Beginning in 2005, operators began addressing the issue of stress
level directly with requests that PHMSA allow operation at the MAOP
levels that the ASME B31.8 Code would allow. With the increasing
interest, PHMSA held a public meeting on March 21, 2006, to discuss
whether to allow increased MAOP consistent with the updated ASME
standards. PHMSA also solicited technical papers on the issue. Papers
filed in response, as well as the transcript of the public meeting, are
in the docket for this rulemaking. Later in 2006, PHMSA again sought
public comment at a meeting of its advisory committee, the Technical
Pipeline Safety Standards Committee (TPSSC). The transcript and
briefing materials for the June 28, 2006, meeting are in the docket for
the advisory committee, Docket ID PHMSA-RSPA-1998-4470-204, 220. This
docket can be found at http://www.regulations.gov. Comments and papers
written during the period these efforts were undertaken overwhelmingly
supported examining increased MAOP as a way to increase energy
efficiency and capacity while maintaining safety.

B.4. Safety Conditions in Special Permits

    In 2005, operators began requesting waivers, now called special
permits, to allow operation at the MAOP levels that the ASME B31.8 Code
would allow. In some cases, operators filed these requests at the same
time they were seeking approval from the Federal Energy Regulatory
Commission (FERC) to build new gas transmission pipelines. In other
cases, operators sought relief from current MAOP limits for existing
pipelines that had been built to more rigorous design and construction
standards.
    In developing an approach to the requests, PHMSA examined the
operating history of lines already operated at higher stress levels.
Canadian and British standards have allowed operation at the higher
stress levels for some time. The Canadian pipeline authority, which has
allowed higher stress levels since 1973, reports the following
regarding pipelines operating at stress levels higher than 72 percent
of SMYS:
     About 6,000 miles of pipelines on the Alberta system,
ranging from six to 42 inches in diameter, were installed or upgraded
between the early 1970s and 2005;
     About 4,500 miles of pipelines on the Mainline system east
of the Alberta-Saskatchewan border, ranging from 20 to 42 inches in
diameter, were installed or upgraded between the early 1970s and 2005;
and,

     More than 600 miles in the Foothills Pipe Line system,
ranging from 36 to 40 inches in diameter, were installed between 1979
and 1998.
    In the United Kingdom, about 1,140 miles of the Northern pipeline
system have been uprated to operate at higher stress level in the past
ten years. Accident rates for pipelines in these countries have not
indicated a measurable increased risk from operation at these higher
operating stress levels.
    In the United States, some 5,000 miles of gas transmission lines
have MAOPs that were grandfathered under Sec.  192.619(c), when the
Federal pipeline safety regulations were adopted in the early 1970s,
continue to operate at stress levels higher than 72 percent of SMYS.
After some accidents caused by corrosion on grandfathered pipelines,
PHMSA considered whether to remove the exception in Sec.  192.619(c).
In 1992, PHMSA decided to continue to allow operation at the
grandfathered pressures (57 FR 41119; Sept. 9, 1992). PHMSA based its
decision on the operating history of two of the operators whose
pipelines contained most of the mileage operated at the grandfathered
pressures. PHMSA noted the incident rate on these pipelines, operated
at stress levels above 72 percent of SMYS, was between 10 percent and
50 percent of the incident rate of pipelines operated at the lower
pressure. Texas Eastern Gas Pipeline Company (now Spectra Energy), the
operator of many of the grandfathered pipelines, attributed the lower
incident rate to aggressive inspection and maintenance. This included
initial hydrostatic testing to 100 percent of SMYS, internal
inspection, visual examination of anomalies found during internal
inspection, repair of defects, and selective pressure testing to
validate the results of the internal inspection. Internal inspection
was not in common use in the industry prior to the 1980s. PHMSA's
statistics show these pipelines continue to have an equivalent safety
record when compared with pipelines operating according to the design
factors in the pipeline safety regulations.
    PHMSA also considered technical studies and required companies
seeking special permits to provide information about the pipelines'
design and construction and to specify the additional inspection and
testing to be used. PHMSA also considered how to handle findings that
could compromise the long-term serviceability of the pipe. PHMSA
concluded that pipelines can operate safely and reliably at stress
levels up to 80 percent of SMYS if the pipeline has well-established
metallurgical properties and can be managed to protect it against known
threats, such as corrosion and mechanical damage.
    Early and vigilant corrosion protection reduces the possibility of
corrosion occurring. At the earliest stage, this includes care in
applying a protective coating before transporting the pipe to the
right-of-way. With the newer coating materials and careful application,
coating provides considerable protection against external corrosion and
facilitates the application of induced current, commonly called
cathodic protection, to prevent corrosion from developing at any breaks
that may occur in the coating. Regularly monitoring the level of
protection and addressing any low readings will detect and correct
conditions that can cause corrosion at an early stage. Vigilant
corrosion protection includes close attention to operating conditions
that lead to internal corrosion, such as poor gas quality. In addition,
for new pipelines, operators' compliance with a rule issued last year
requiring greater attention to internal corrosion protection during
design and construction (72 FR 20059; Apr. 23, 2007) will prevent
internal corrosion. Finally, corrosion protection includes internal
inspection and other assessment techniques for early detection of both
internal and external corrosion.
    One of the major causes of serious pipeline failure is mechanical
damage caused by outside forces, such as an equipment strike during
excavation activities. Burying the pipeline deeper, increased
patrolling, and additional line marking help prevent the risk that
excavation will cause mechanical damage. Further, enhanced pipe
properties increase the pipe's resistance to immediate puncture from a
single equipment strike. Improved toughness increases the ability of
the pipe to withstand mechanical damage from an outside force and may
also limit any failure consequences to leaks rather than ruptures. This
toughness usually allows time for the operator to detect the damage
during internal inspection well before the pipe fails.
    To evaluate each request for a special permit, PHMSA established a
docket and sought public comment on the request. We received several
public comments, most in response to the first special permits
considered. Many of the comments supported granting the special
permits. Those who were not supportive may have underestimated the
significance of the safety upgrades required for the special permits. A
few commenters raised technical concerns. Among these were questions
about the impact of rail crossings and blasting activities in the
vicinity of the pipeline. The special permits did not change the
current requirements where road crossings exist and added a requirement
to monitor activities, such as blasting, that could impact earth
movement. Some commenters expressed concern about the impact radius of
the pipeline operating at a higher stress level. PHMSA included
supplemental safety criteria to address the increased radius. The
remainder of the comments addressed concerns, such as compensation or
aesthetics, which were outside the scope of the special permits. PHMSA
special permits do not address issues on siting, which are governed by
the FERC.
    PHMSA expects to issue seven special permits, and possibly more, in
response to these requests. In each case, PHMSA has provided oversight
to confirm the line pipe is, or will be (for pipe yet to be
constructed), as free of inherent flaws as possible, that construction
and operation do not introduce flaws, and that any flaws are detected
before they can fail. PHMSA accomplishes this by imposing a series of
conditions on the grant of special permits. The conditions imposed as
part of the special permits are designed to address the potential
additional risk involved in operating the pipeline at a higher stress
level. A proposed pipeline must be built to rigorous design and
construction standards, and the operator requesting a special permit
for an existing pipeline must demonstrate that the pipeline was built
to rigorous design and construction standards. These additional design
and construction standards focused on producing a high quality pipeline
that is free from inherent defects that could grow more rapidly under
operation at a higher stress level and is more resistant to expected
operational risks. In addition, PHMSA requires the operator of a
pipeline receiving a special permit to comply with operation and
maintenance (O&M) requirements that exceed current pipeline safety
regulations. These additional O&M and integrity management requirements
focused on the potential for corrosion and mechanical damage and on
detecting defects before the defects can grow to failure.

B.5. Codifying the Special Permit Standards

    This rule puts in place a process for managing the life-cycle of a
pipeline operating at a higher stress level based on our experience
with the special permits. Integrity management focuses on managing and
extending the service

life of the pipeline. Life-cycle management goes beyond the operations
and maintenance practices, including integrity management, to address
steel production, pipeline manufacture, pipeline design, and
installation.
    Industry experience with integrity management demonstrates the
value of life-cycle management. Through baseline assessments in
integrity management programs, gas transmission operators identified
and repaired 2,883 defects in the first three years of the program
(2004, 2005, and 2006). More than 2,000 of these were discovered in the
first two years as operators assessed their highest risk, generally
older, pipelines. In a September 2006 report, GAO-09-946, the
Government Accountability Office noted this data as an early indication
of improvement in pipeline safety. In order to qualify for operation at
higher stress levels under this rule, pipelines will be designed and
constructed under more rigorous standards. Baseline assessment of these
lines will likely uncover few defects, but removing those few defects
will result in safer pipelines. In addition, the results of the
baseline assessment will aid in evaluating anomalies discovered during
future assessments.
    This rule, based on the terms and conditions of the special permits
allowing operation at higher stress levels, imposes similar terms and
conditions and limitations on operators seeking to apply the new rule.
The terms and conditions, which include meeting design standards that
go beyond current regulation, address the safety concerns related to
operating the pipeline at a higher stress level. PHMSA will step up
inspection and oversight of pipeline design and construction, in
addition to review and inspection of enhanced life-cycle management
requirements for these pipelines.
    With special permits, PHMSA individually examined the design,
construction, and O&M plans for a particular pipeline before allowing
operation at a higher pressure than currently authorized. In each case,
PHMSA conditioned approval on compliance with a series of rigorous
design, construction, O&M, and management standards, including enhanced
damage prevention practices. PHMSA's experience with these requests for
special permits led to the conclusion that a rule of general
applicability is appropriate. With a rule of general applicability, the
conditions for approval are established for all without need to craft
the conditions based on individual evaluation. Thus, this rule sets
rigorous safety standards. In place of individual examination, the rule
requires senior executive certification of an operator's adherence to
the more rigorous safety standards. An operator seeking to operate at a
higher pressure than allowed by current regulation must certify that a
pipeline is built according to rigorous design and construction
standards and must agree to operate under stringent O&M standards.
After PHMSA or 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) receives an operator's
certification indicating its intention to operate at a higher operating
stress level, PHMSA or the state would then follow up with the operator
to verify compliance. As with the special permits, this rule would
allow an operator to qualify both new and existing segments of pipeline
for operation at the higher MAOP, provided the operator meets the
conditions for the pipeline segment.
    Several types of pipeline segments will not qualify under this
rule. These include the following:
     Pipeline segments in densely populated Class 4 locations.
In addition to the increased consequences of failure in a Class 4
location, the level of activity in such a location increases the risk
of excavation damage.
     Pipeline segments of grandfathered pipeline already
operating at a higher stress level but not constructed in accordance
with modern standards. Although grandfathered pipeline has been
operated successfully at the higher stress level, PHMSA or the state
would examine any further increases individually through the special
permit process.
     Bare or ineffectively coated pipe. This pipe lacks the
coating needed to prevent corrosion and to make cathodic protection
effective.
     Pipelines with wrinkle bends. Section 192.315(a) currently
prohibits wrinkle bends in pipeline operating at hoop stress exceeding
30 percent of SMYS.
     Pipelines experiencing failures indicative of a systemic
problem, such as seam flaws, during initial hydrostatic testing. Such
pipe is more likely to have inherent defects that can grow to failure
more rapidly at higher stress levels.
     Pipe manufactured by certain processes, such as low
frequency electric welding process.
     Pipeline segments which cannot accommodate internal
inspection devices.
    We are establishing slightly different requirements for segments
that have already been operating and those which are to be newly built.
Some variation is necessary or appropriate for an existing pipeline.
For example, the requirement for cathodically protecting pipeline
within 12 months of construction is an existing requirement for all
pipelines. A requirement for the operator of an existing pipeline
segment to prove that the segment was in fact cathodically protected
within 12 months of construction provides greater confidence in the
condition of the existing segment. Allowing proof of five percent fewer
nondestructive tests done on an existing segment at the time of
construction recognizes the possibility that some welds may not be
tested when 100 percent nondestructive testing is not required. The
overriding principle in the variation is to allow qualification of a
quality pipeline with minimal distinction. Based on our review of
requests for special permits on existing pipelines, PHMSA does not
believe the more rigorous standards we are requiring are too high for
existing segments of modern design and construction. Setting the
qualification standards lower for existing pipeline segments could
encourage operators to construct a pipeline at the lower standards and
seek to raise the operating pressure at some future date.
    PHMSA acknowledges this rule may not cover all conditions
encountered by a pipeline operator. Further, operators may have
innovative alternative methods to the guidelines contained in this
rule. To that end, operators may apply to PHMSA or 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) for a special permit requesting to implement
the alternative methods.

B.6. How To Handle Special Permits and Requests for Special Permits

    A number of pipeline operators have submitted requests for special
permits seeking relief from the current design requirements to allow
operation at higher stress levels. For the most part, this rule
addresses the relief requested. PHMSA has already granted many of these
under terms and conditions that may vary slightly from those in this
final rule. In some cases, the relief granted is specific to the relief
requested by the operator and extends beyond the scope of this
rulemaking. PHMSA has continued review of pending special permit
applications while working on this rulemaking, in recognition that a
final rule may not be issued by the time an operator intended to
operate its pipeline at a higher operating stress level. With the
publication of this final

rule, this case-by-case approach to approving operation under a special
permit at higher operating stress levels is no longer needed.
    PHMSA will terminate its review of any pending applications for
special permits associated with operation at higher operating stress
levels once this final rule is issued. Operators of those pipelines
must comply with this final rule in order to operate their pipelines at
a higher alternative MAOP. PHMSA will examine special permits that have
already been granted, as appropriate, to determine if any modifications
are needed in light of safety decisions made in preparing this rule.

B.7. Statutory Considerations

    Under 49 U.S.C. 60102(a), PHMSA has broad authority to issue safety
standards for the design, construction, O&M of gas transmission
pipelines. Under 49 U.S.C. 60104(b), PHMSA may not require an operator
to modify or replace existing pipelines to meet a new design or
construction standard. Although this rule includes design and
construction standards, these standards simply add more rigorous, non-
mandatory requirements. This rule does not require an operator to
modify or replace existing pipelines or to design and construct new
pipeline in accordance with these non-mandatory standards. If, however,
a new or existing pipeline meets these more rigorous standards, the
rule allows an operator to elect to calculate the MAOP for the pipeline
based on a higher stress level. This would allow operation at an
increased pressure over that otherwise allowed for pipeline built since
the Federal regulations were issued in the 1970s. To operate at the
higher pressure, the operator would have to comply with more rigorous
O&M, and management requirements.
    Under 49 U.S.C. 60102(b), a gas pipeline safety standard must be
practicable and designed to meet the need for gas pipeline safety and
for protection of the environment. PHMSA must consider several factors
in issuing a safety standard. These factors include the relevant
available pipeline safety and environmental information, the
appropriateness of the standard for the type of pipeline, the
reasonableness of the standard, and reasonably identifiable or
estimated costs and benefits. PHMSA has considered these factors in
developing this rule and provides its analysis in the preamble.
    PHMSA must also consider any comments received from the public and
any comments and recommendations of the TPSSC. These are discussed
below.

C. Comments on the NPRM

    PHMSA received comments from 19 organizations in response to the
NPRM. These included eleven pipeline operators, four trade associations
and related organizations, three steel/pipe manufacturers, and one
state pipeline safety regulatory agency.

C.1. General Comments

API 5L, 44th Edition
    Many commenters noted that pipe material/design requirements in
American Pipeline Institute (API) Standard 5L (API 5L) have been
significantly revised in the 44th edition, which they stated would be
in effect by the time a final rule is issued. These commenters
generally suggested that PHMSA should defer to, or incorporate,
requirements from the 44th edition where applicable rather than
establishing different technical requirements in regulation.
Response
    API 5L, 43rd edition, is currently incorporated by reference into
the Code of Federal Regulations (CFR). PHMSA has begun a technical
review of the 44th edition to determine whether and to what extent it
is appropriate to update this reference or if exceptions need be taken
when so incorporating the standard. PHMSA cannot reference requirements
in the 44th edition until this review is completed and the regulations
have been revised to incorporate the new edition. Where differences in
the 44th edition would affect requirements in this rule, appropriate
changes will be made when that edition is incorporated.
Effect on Special Permits
    All commenters who addressed the question suggested that
requirements in a final rule should not apply retroactively to
pipelines operating at alternative MAOP based on special permits issued
after detailed review by PHMSA. One pipeline operator provided a legal
analysis maintaining that such retroactive application would be
contrary to PHMSA's statutory authority. These organizations also
commented that PHMSA should continue review of special permit
applications until the final rule is issued, noting that in many cases
operation at the proposed higher MAOP is necessary to meet contractual
commitments operators have made in anticipation of a special permit
being granted and to meet national energy needs.
Response
    As noted above, PHMSA continued reviewing special permit
applications throughout this rulemaking proceeding, generally applying
the same criteria adopted in this rule. Having now published the final
rule, we consider it unnecessary to complete review of pending special
permit applications on the subject. Accordingly, PHMSA intends to
terminate these proceedings, with appropriate notice to the individual
applicants.
    In contrast, this regulatory action has no effect on the status of
special permits or waivers currently in effect. As we explained
recently in Docket No. PHMSA-2007-0033, Pipeline Safety: Administrative
Procedures, Address Updates, and Technical Amendments, (FR Volume 73,
No. 61, 16562, published March 28, 2008), PHMSA reserves the right to
revoke or modify a special permit or waiver based on an operator's
failure to comply with the conditions of the special permit/waiver or
on a showing of material error, misrepresentation, or changed
circumstances. Although an operator may elect to surrender its special
permit at any time, nothing in this rule requires the operator to do so
or otherwise triggers reopening of a special permit/waiver currently in
effect. The existing MAOP special permits were issued based upon a
PHMSA review of the operator's engineering, construction, O&M
procedures and operating history. While some of the pipeline segments
may not meet all of the requirements specified in this final rule, the
operational history and O&M practices provide an equivalent level of
safety as provided in this final rule. Furthermore, whether a pipeline
is operating at higher MAOP under this rule or a special permit/waiver,
PHMSA will monitor and enforce compliance with the applicable
conditions and safety controls.
Structure
    One state pipeline safety regulatory agency expressed concern about
the complexity and inconsistency being added to the regulations as a
result of the structure of the proposed rule. The state agency noted
that the proposal would add many pages to part 192 that would apply to
only a limited number of gas transmission operators. The agency
suggested that it would be more effective, and cause less confusion, if
requirements for pipelines operating at an alternative MAOP were
presented in a separate subpart, applicable only to those pipelines.

Response
    PHMSA has not previously used a separate subpart to include varied
requirements applicable to specific types of pipelines. Instead,
subparts have been used for individual topics, such as Corrosion
Control or Integrity Management. PHMSA considers it more appropriate to
incorporate requirements applicable to each subpart as the requirements
in this rule implicate several subparts. PHMSA also notes that no other
commenters indicated that the structure of the proposed rule was
confusing. PHMSA has retained the structure of the proposal in this
final rule. PHMSA intends to post this notice of final rulemaking on
its web site, which will provide a reference for pipeline operators
that includes all of the requirements associated with alternative MAOP
in one document.

C.2. Comments on Specific Provisions in the Proposed Rule

C.2.1. Section 192.7, Incorporation by Reference

    Interstate Natural Gas Association of America (INGAA) and three
pipeline operators supported incorporation of American Society of
Testing and Materials (ASTM) standard ASTM A-578/A578M-96 into the
regulations. These commenters generally noted that this action is
consistent with reliance on consensus standards, which they support.
American Gas Association (AGA) and the Gas Piping Technology Committee
(GPTC) took the contrary position and opposed incorporation of the ASTM
standard. GPTC commented that the standard is used by one mill and that
other mills use other standards (including International Standards
Organization (ISO) standards). GPTC also noted that there are a number
of equivalent standards and that PHMSA should not select one for
incorporation. AGA added that incorporating the standard could have
unintended consequences of making the rule too prescriptive and
precluding the use of equivalent standards.
Response
    The final rule incorporates ASTM A578/A578M-96 into the
regulations. Incorporation by reference makes the provisions of the
standard apply, when it is referenced in a regulation, in the same
manner as if they were written in the CFR. Referencing consensus
standards wherever possible is the policy of the Federal government.
    This standard is referenced in the regulation for assuring plate/
coil quality control (QC). That reference requires that ultrasonic (UT)
testing be conducted in accordance with the standard, API 5L paragraph
7.8.10, or equivalent. The pipe must also be manufactured in accordance
with API 5L which is already referenced in Sec.  192.7. PHMSA considers
that the allowance for use of an equivalent standard renders moot the
concerns expressed by AGA and GPTC.

C.2.2. Design Requirements

Section 192.112(a), General Standards for the Steel Pipe
    Carbon equivalent: INGAA, five pipeline operators and two pipe
manufacturers all noted that the proposed limit in paragraph (a)(1) on
carbon equivalent (CE) (0.23 percent Pcm) is inconsistent with the 44th
edition of API 5L. INGAA and one operator suggested deleting the limit
from the proposed rule. Two operators noted that the NPRM described no
analysis or data showing the need for a different limit. Several
commenters indicated that high-strength pipe (grades X-80 and above) is
difficult to achieve with the stated limit. One operator suggested that
weldability is the key issue and that allowance for a higher CE is
particularly important for high-strength and strain-based pipe. A steel
manufacturer objected to sole reliance on the Pcm formula for
determining the CE value.
Response
    PHMSA agrees that the limit in API 5L is acceptable. PHMSA has
changed the limit for CE to 0.25 Pcm (Ito-Bessyo formula for CE), which
is consistent with API 5L. PHMSA does not agree that no limit should be
included in the CFR. PHMSA considers that a limit is necessary to
assure the quality of steel used for pipelines to operate at an
alternative MAOP. Weldability tests are not timely for determining the
acceptability of steel, as they cannot be performed until pipe is
manufactured. Recent experience with several new pipelines using X-80
steel has indicated that such high strength steel can meet the CE
limit. PHMSA does not currently have experience with steels of grades
higher than X-80 and will need to understand what is important for such
pipe grades as they are used.
    PHMSA acknowledges that there are other methods for calculating the
CE value of steel. The Pcm formula included in the proposed rule is a
method used by several mills. PHMSA has revised the final rule to
include use of an alternate International Institute of Welding (IIW) CE
formula, used by other mills for determining CE.
    Diameter to thickness ratio: INGAA and three pipeline operators
suggested deleting the limit in proposed paragraph (a)(3) on the ratio
of pipe diameter to thickness (D/t). They maintained that this limit
may be inappropriate for high-grade pipe and that the concerns that
might underlie such a limit are adequately addressed by the proposed
rule and common construction practices and quality assurance (QA). One
operator noted that ovality and denting issues are addressed by the
proposed construction requirements of Sec.  192.328, that QA is
required by proposed Sec.  192.620(d)(9), and that the baseline
geometry ILI and the provisions of the ASME Code would also address the
underlying concerns.
Response
    PHMSA has retained the proposed limit. PHMSA adopted this limit
(i.e., D/t <= 100) based upon presentations made by industry experts at
the public meeting on ``Reconsideration of Maximum Allowable Operating
Pressure in Natural Gas Pipelines'' held on March 21, 2006 in Reston,
VA. Higher D/t ratios can lead to excessive denting during
transportation, construction bending, pipe stringing on the right-of-
way, backfilling, and hydrostatic testing.
Section 192.112(b), Fracture Control
    Several commenters noted that some requirements included in the
proposed rule are being eliminated or significantly revised in the 44th
edition of API 5L. The steel/pipe manufacturers suggested referencing
the new standard to, among other things, avoid unnecessarily limiting
approaches to deriving arrest toughness and treating all sizes and
types of pipe (e.g., seamless) the same for purposes of the drop weight
test.
    INGAA and three pipeline operators suggested a change to allow a
crack arrest design other than mechanical arrestors if crack
propagation cannot be made self-limiting. (One operator noted that
Clock Spring \1\ is marketed as a crack arrestor). They suggested that
a rule should allow an option for engineering analysis, including an
analysis of consequences. One operator noted that this option could be
particularly important for high-pressure, large-diameter pipelines. Two
operators generally supported the proposed approach for fracture
control if self-arrest is attainable. They noted that it is critical
that operators have a plan and consider the potential under-

conservativeness of Charpy toughness equations for high grade pipe (X-
70 and above).
---------------------------------------------------------------------------

    \1\ Clock Spring is a commercially available composite sleeve
used for pipeline repairs.
---------------------------------------------------------------------------

Response
    PHMSA has not yet incorporated the 44th edition of API 5L into the
regulations. PHMSA is conducting a technical review of this edition to
determine if it is acceptable for incorporation. If, after that review,
PHMSA determines that the standard is acceptable, PHMSA will propose to
incorporate the 44th edition and change other affected rules as
appropriate.
    The final rule requires an overall fracture control plan to resist
crack initiation and propagation and to arrest a fracture within eight
pipe joints with a 99 percent occurrence probability and within five
pipe joints with a 90 percent occurrence probability. Research has
shown that an effective fracture plan should include acceptable Charpy
impact and drop weight tear tests, which are required in this final
rule.
    PHMSA considers composite sleeves to be suitable mechanical crack
arrestors. Operators could use composite sleeves for this purpose,
install periodic joints of thicker-walled pipe, or use other design
features to provide crack arrest if it is not possible to achieve the
toughness properties specified in the rule and also assure self-
limiting arrest. PHMSA has revised the language in this final rule to
allow additional design features and to make mechanical crack arrestors
an example of such features rather than the only method allowed.
Section 192.112(c), Plate/Coil Quality Control
    One pipeline operator and two pipe manufacturers suggested
expanding the mill control inspection program to a full internal
quality management program and including caster and plate/coil/pipe
mills.
    INGAA, three pipeline operators and two pipe manufacturers
commented that the specificity of requirements applicable to mill
inspection should be reduced. These commenters agreed that a macro etch
test is appropriate but suggested that the details of how this test is
applied should be left to decisions of the mill and the pipe purchaser.
They suggested that API 5L provides a foundation for those decisions
and the specific requirements in the proposed rule add unnecessary cost
impact. One pipe manufacturer noted that the Mannesmann scale is very
subjective, while a second separately commented that reference to the
Mannesmann scale should be deleted because it is proprietary and thus
inappropriate for inclusion in a regulation. One operator requested
that the mill inspection requirements, including those for macro etch
and UT examination, be explicitly limited to new pipelines, noting that
it is unlikely these tests were performed for any existing pipelines
and that they have minimal relevance for existing pipelines that would
be subject to the proposed rule.
    INGAA and four pipeline operators suggested that an alternative to
the UT testing specified should be allowed for identifying laminations.
They suggested that a full-body UT inspection, for example, should be
acceptable.
    One operator and two manufacturers commented that it is
inappropriate to use the proposed macro etch test and acceptance
criteria as a heat/slab rejection criteria. These commenters noted that
no consensus standard references this test. The operator maintained
that the test does not accomplish what PHMSA suggested in the preamble
of the NPRM, that it is a lagging rather than a leading test and its
use as an acceptance test without a retest allowance could result in
rejection of up to 2,000 tons of steel or more. The operator suggested
that this should be a mill control test rather than an acceptance test
with specifics, including retest allowance, to be negotiated between
the mill and pipe purchaser.
    One operator and one manufacturer noted that ASTM A578 is a plate
UT inspection standard. They commented that specifying this standard
for coil/pipe is beyond its scope. They also commented that we gave no
basis for proposing that 50 percent of surface and 90 percent of joints
be examined. They noted that pipe seam welds and pipe ends are
inspected radiographically or by UT and that additional UT is more
appropriately a purchaser-specified requirement. Another operator also
suggested that the 50 percent surface coverage requirement be deleted
in favor of reference to ASTM A578/A578M.
    Two manufacturers suggested that the rule allow UT on plate/coil or
pipe body, noting that most United States mills lack equipment to
perform ASTM A578 testing. Another manufacturer suggested that a
combination of electromagnetic inspection (EMI) and UT inspection is
superior and would produce the most dramatic impact. This combination,
according to this manufacturer, is also applicable to seamless and
electric resistance welded (ERW) pipe.
    One manufacturer recommended that the inspection program of
proposed section 192.112(c)(2)(ii) be limited to submerged arc welded
(SAW) pipe, and that the acceptance criteria for UT testing be
referenced to ASTM A578 or equivalent. This commenter noted that
laminations are not a significant issue for modern pipe.
Response
    PHMSA agrees that an ``internal quality management program'' is
more descriptive than a ``mill control inspection program'' and that
such a program should be required at all mills associated with the
manufacture of steel and pipe. The final rule has been revised
accordingly.
    PHMSA considers that a macro etch test or other equivalent method
is needed to identify inclusions that may cause centerline segregation
during the continuous casting process. The acceptance criteria must be
agreed to between the purchaser and the mill. PHMSA has added an
alternative to the requirement for a macro etch test consisting of an
operator QA monitoring plan that includes audits conducted by the
operator (or an agent operating under its authority) of: (a)
Steelmaking and casting facilities; (b) QC plans and manufacturing
procedure specifications (MPS); (c) equipment maintenance and records
of conformance; (d) applicable casting superheat and speeds; and (e)
centerline segregation monitoring records to ensure mitigation of
centerline segregation during the continuous casting process.
    PHMSA agrees that alternate methods to test the pipe body for
laminations, cracks, and inclusions should be acceptable and has
revised the rule to allow methods per API 5L Section 7.8.10 or ASTM
A578-Level B, or other equivalent methods. PHMSA understands that it is
unlikely that many existing pipelines were manufactured using processes
that included the specified examinations but does not consider that
sufficient reason for excluding existing pipelines from the
requirements.
    The requirement for 50 percent of surface and 95 percent of lengths
of pipe to be UT tested was set to ensure adequate QC standards. PHMSA
agrees that the specified QC requirements also must be practical. In
the final rule, we have reduced the requirement for 50 percent of
surface coverage to 35 percent because we recognize that it may be
difficult to achieve 50 percent coverage for pipe manufactured with
helical seams.
    PHMSA has not deleted reference to the Mannesmann scale, which is
widely used by steel manufacturers. In

addition, the regulation allows for use of equivalent measures.
    PHMSA does not agree that the inspection program of proposed
192.112(c)(2)(ii) should be limited to SAW pipe. PHMSA considers this
requirement to be an overall quality management tool and not just for
laminations. Additionally, PHMSA notes that at least one recently
constructed pipeline has had problems with laminations.
Section 192.112(d), Seam Quality Control
    INGAA, four pipeline operators, and two pipe manufacturers all
recommended additional reliance on the procedures of API 5L 44th
edition. The manufacturers would have referenced API 5L for toughness
requirements and made them applicable to weld and heat affected zone in
SAW pipe only. They noted that the proposed requirement is
inappropriate for ERW pipe, that the specified toughness is higher than
that called for in API 5L and is not necessary. The manufacturers
believe that fracture arrest capabilities are not needed in weld metal,
since staggered seams in pipeline construction result in arrest
occurring in the pipe body.
    INGAA and three pipeline operators would have eliminated reference
to specific hardness testing or a maximum hardness level, arguing that
API 5L contains sufficient guidance. They further noted that the
specified hardness of 280 Vickers (Hv10) is only for sour gas. One
manufacturer would have relaxed the hardness requirement to 300 Hv10
and allowed for equivalent test methods (per ASTM E140). Another would
have specified a maximum hardness ``appropriate for the pipeline
design'' vs. specifying a limit. The first manufacturer noted that API
5L does not specify hardness limits except for sour gas service or
offshore pipelines and that the technical justification for these
limits on other pipe is not obvious. The manufacturers maintained that
limiting hardness may not allow attaining the best weld properties and
that 280 Hv10 is likely not attainable for pipe grades X-80 and above.
    Two pipe manufacturers requested that the rule be clarified to
indicate that the seam QC requirements apply only to longitudinal or
helical seams. They noted that pipe mill jointer welds require
radiography per API 1104 and that significant capital expense would be
required for pipe mills to UT test jointer and skelp end welds after
cold expansion and hydrostatic testing.
Response
    PHMSA has not yet incorporated the 44th edition of API 5L into the
regulations. PHMSA is conducting a technical review of this edition to
determine if it is acceptable for incorporation. If, after review,
PHMSA determines that the standard is acceptable, PHMSA will propose to
incorporate the 44th edition and propose changes to other affected
regulations as appropriate.
    PHMSA has deleted the proposed limit on toughness. This limit was
not included in the conditions applied to special permits issued for
alternative MAOP operation. Pipe procured to modern standards generally
meets the proposed limit, and other requirements in this rule, provide
for crack arrest. Thus, PHMSA concluded that a toughness limit was not
needed.
    PHMSA does not agree that it is not necessary to specify a hardness
limit. All recent pipelines for which special permits have been issued
to operate at alternative MAOP have met the proposed hardness limit
without apparent difficulty. This includes X-80 pipe. The requirement
helps assure that only high-quality steel is used for pipelines to be
operated at alternative MAOP. Hardness must be limited to assure welds
are not susceptible to cracking. The proposed limit has been retained
in the final rule.
    PHMSA intends the proposed seam inspection requirements to apply to
pipe seam welds and not to jointer or skelp welds. The title of this
subparagraph is ``Seam quality control,'' and its requirements all
refer to ``seam welds'' or ``seams.'' PHMSA does not consider that
additional changes are needed to clarify the applicability of these
requirements.
Section 192.112(e), Mill Hydrostatic Test
    Most commenters objected to the proposed requirement that mill
hydrostatic tests be held for 20 seconds. They noted that mills
typically follow API 5L, which specifies a hydrostatic test of 10
seconds and that changing this standard could reduce mill productivity.
One operator also noted that a more rigorous qualification test is
already specified elsewhere in the proposed regulation.
    One manufacturer would have limited the required maximum test
pressure to 3,000 psi if there are physical limitations in mill test
equipment that preclude obtaining higher pressures. The manufacturer
stated that most mills cannot achieve test pressures above 3,000 psi,
which is the maximum specified in API 5L and that upgrades to equipment
would cost from $0.5 to $4 million per tester.
Response
    PHMSA agrees that a 20-second mill hydrostatic test is not needed
and has revised the final rule to reduce the required hold time to 10
seconds. While a longer mill hydrostatic test may allow the discovery
of more pipe defects, the benefit is marginal. The pipeline will later
be subject to a much longer hydrostatic test prior to being placed in
service according to 192.505(c). Moreover, in the case of Class 1 and 2
locations, the pipe will be tested at a higher stress level than the
mill hydrostatic test according to 192.620(a)(2).
    PHMSA does not consider it appropriate to limit the maximum test
pressure to reflect the reported mill limitations. In practice, the
need for tests above 3,000 psi should be rare. Test pressures that high
would only be required for pipeline in a Class 3 location operating at
a very high MAOP.
Section 192.112(f), Coating
    INGAA, GPTC, and eight pipeline operators all objected to the
proposed requirements that would have limited operation at an
alternative MAOP to pipe coated with fusion bonded epoxy (FBE). The
commenters noted that specifying any single coating type would stifle
innovation. They suggested that a performance-based requirement would
be more appropriate. The important performance characteristics they
identified include non-disbonding and non-cracking. Two operators would
add non-shielding, and GPTC suggested specifying that coating must meet
or exceed the protection of FBE.
    GPTC and one operator requested clarification that girth welds can
be coated with other than FBE. GPTC also requested clarification that
the proposed requirement in subparagraph 2 that coatings used for
trenchless installation must resist abrasion and other damage applies
to the coatings described under subparagraph 1.
Response
    PHMSA agrees that specifying a particular coating could stifle
innovation and we have revised the final rule to require non-shielding
coatings. Eliminating reference to FBE coating in this section obviates
the need for additional changes to note that girth welds can be coated
with other than FBE.
    PHMSA has made a minor change in response to GPTC's request for
clarification. Subparagraph 192.112(f)(2)

now requires that coatings used for trenchless installation must resist
abrasions and other installation damage ``in addition to being non-
shielding.''
Section 192.112(g), Flanges and Fittings
    INGAA and three pipeline operators generally supported the proposed
requirements for certification records and a pre-heat procedure for
welding of components with CE greater than 0.42 percent, but maintained
that existing standards and operator supplemental requirements are
adequate to assure the integrity of flanges and fittings. The operators
cited specific standards to which fittings and flanges should be
purchased. Another operator noted that the proposed requirements go
beyond API and ASTM standards, and suggested that the new requirements
should be part of an industry standard. This operator also suggested
that PHMSA establish a minimum size below which certifications would
not be required.
    GPTC requested clarification as to what certification is required
and what requirements/specifications are to be certified.
Response
    PHMSA has concluded that no changes are needed to the standards
proposed for flanges and fittings. It is likely that flanges and
fittings procured to current standards will meet the rule's
requirements. PHMSA will review the degree of compliance during
inspections of pipelines being constructed or upgraded for operation at
an alternative MAOP. PHMSA does not agree that the proposed
requirements go beyond API and ASTM standards. Fittings, flanges and
valves manufactured to API, ASTM, and/or ASME/ANSI standards should not
be operated above the maximum operating pressure limits of those
industry standards for the product rating. This rule change is not
intended to increase maximum operating pressure limits or designated
pressure or temperature rating of referenced code standards.
    In the final rule, PHMSA has clarified that certification must
address chemistry, strength and wall thickness.
Section 192.112(h), Compressor Stations
    Commenters expressed concern about the proposed requirement to
limit compressor station discharge temperatures to 120 degrees
Fahrenheit (49 degrees Celsius) unless testing shows the coating can
withstand higher temperatures in long-term operations. INGAA and four
pipeline operators would allow ``research'' in addition to testing to
permit operation above 120 degrees Fahrenheit. INGAA submitted a white
paper titled ``A Review of the Performance of Fusion-Bonded Epoxy
Coatings on Pipelines at Operating Temperatures Above 120 [deg]F'',
dated May 16, 2008, describing research it believes is relevant. The
commenters stated that more testing is not needed, because FBE coating
has been shown effective by research and experience in service. They
maintained that disbonding may occur but is irrelevant because FBE
coating is conductive and cathodic protection is still effective.
    One pipeline operator would have allowed operation at a higher
compressor station discharge temperature if justified by test or data
held by the manufacturer, coating applicator, or operator. The operator
maintained that modern coating can withstand higher temperatures, and
that maintaining 120 degrees Fahrenheit may be impractical on hot days
(during which peak loads often occur) in southern locations. Another
operator suggested allowing operators to rely on FBE manufacturers'
specifications as the ``testing'' adequate to allow operation above 120
degrees Fahrenheit, limiting operation to 90 percent of the
manufacturer's continuous operating temperature. Another operator
suggested allowing a long-term coating integrity monitoring program as
an alternative to designing compressor stations to limit discharge
temperature to 120 degrees Fahrenheit.
    A state pipeline safety regulatory agency suggested that
alternative approaches be allowed. The agency suggested that operators
could install heavier walled pipe and operate at conventional MAOP for
the distance required to assure that pipe wall temperatures would be
below 120 degrees Fahrenheit. This commenter stated its belief that
this would be a simpler and cheaper solution to the concern over
compressor station outlet temperature and that its use should not be
precluded.
Response
    PHMSA is not persuaded by the arguments put forth by commenters,
and in the INGAA white paper titled ``A Review of the Performance of
Fusion-Bonded Epoxy Coatings on Pipelines at Operating Temperatures
Above 120 [deg]F'', dated May 16, 2008, that operation above 120
degrees Fahrenheit is simply acceptable. In fact, the INGAA white paper
confirms that disbonding and possibly cracking of FBE coating is more
likely to occur at operating temperatures above 120 degrees Fahrenheit.
PHMSA disagrees that disbonding is irrelevant because disbonded FBE
remains conductive and an operating cathodic protection system will
protect the pipeline from corrosion.
    External corrosion is one of the most significant threats affecting
steel pipelines. PHMSA regulations require two levels of protection
against this threat: Coating and cathodic protection. These
requirements are intended to provide redundant protection. If coating
fails, cathodic protection continues to protect the pipe. If cathodic
protection fails, the coating is still present. PHMSA agrees that it is
important that disbonded coating remain conductive to assure continued
protection by cathodic protection. This is why the rule has been
revised to require ``non-shielding'' coating. At the same time, PHMSA
does not consider it acceptable to ignore known circumstances in which
one of the protections against corrosion is likely to fail simply
because the other exists. If PHMSA believed only one level of
protection were needed, the regulations would require either coating or
cathodic protection. INGAA's white paper confirms that there is a
significant likelihood that one of the levels of protection against
corrosion (i.e., coating) will fail if operated above 120 degrees
Fahrenheit. For pipelines to be operated at an alternative MAOP, where
the margin for corrosion is smaller than for pipelines conforming to
the existing regulations, PHMSA will not accept this higher likelihood
of failure of the coating system.
    Nevertheless, PHMSA recognizes that improvements in coating systems
may allow operation above 120 degrees Fahrenheit without significantly
higher likelihood of disbonding. Thus, the rule allows operation above
this temperature if research, testing, and field monitoring tests
demonstrate that the coating type being used will withstand long-term
operation at the higher temperature. The operator must assemble and
maintain the data supporting higher-temperature operation. Research,
testing and field monitoring must be for coating by the same
manufacturer and must be specific to the brand of coating (if the
manufacturer makes more than one brand), application temperature, or
operating temperature rated coating.
    PHMSA agrees that a long-term coating integrity monitoring program
can also assure that coating remains effective at higher operating
temperatures, but the effectiveness of such a program depends on how it
is structured and implemented. PHMSA would expect, for example, that a
monitoring program being used as a basis for operating at temperatures
above 120 degrees Fahrenheit would include periodic examinations to
assure

coating integrity (e.g., direct current voltage gradient). PHMSA has
modified the final rule to allow a long-term coating integrity
monitoring program to be used as a basis for allowing pipe temperatures
in excess of 120 degrees Fahrenheit, but operators must submit their
programs to the PHMSA pipeline safety regional office in which the
pipeline is located for review before pipeline segments may be operated
at alternative MAOP at these higher temperatures. PHMSA's review will
help assure that the monitoring programs are comprehensive enough to
assure long-term coating integrity, to identify instances in which
coating integrity becomes degraded, and to address those problems. 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.
    Where compressor station compression ratios raise the temperature
of the flowing gas to above 120 degrees Fahrenheit, operators should
consider installing gas coolers at compressor stations. This practice
has been successfully used in the industry to cool the gas stream to
not damage the pipe external coating.
    PHMSA agrees that the alternative of heavier walled pipe operated
at conventional MAOP for the distance required to assure that pipe wall
temperatures do not exceed 120 degrees Fahrenheit suggested by the
state regulator is also an acceptable method of addressing the concern
of high-temperature operation. PHMSA has made minor changes to the rule
to make it clear that this option is not precluded.

C.2.3. Construction Requirements

Section 192.328(a), Quality Assurance (QA)
    Four pipeline operators supported the QA requirements of proposed
Sec.  192.328(a). A state pipeline safety regulator noted that
subparagraph 2(ii) duplicated requirements in proposed Sec.
192.620(c)(5) and questioned why both sub-rules were needed.
Response
    PHMSA's experience in regulating pipelines operating at higher
MAOPs under special permits has indicated that control of quality is
subject to frequent problems. As a result, PHMSA considers that an
explicit requirement for a QA plan during construction is needed. The
requirements of proposed Sec.  192.620(c)(5) also addressed quality
concerns, but they relate principally to personnel qualification. As
described below, this proposed paragraph has been revised in the final
rule to more explicitly address the qualification of personnel
performing construction tasks.
Section 192.328(b), Girth Welds
    INGAA and four pipeline operators suggested moving the requirement
for testing of girth welds on existing pipelines from Sec.  192.328 to
Sec.  192.620. They believe that the requirement is inappropriately
located in a construction section that is not otherwise applicable to
existing pipe.
Response
    PHMSA agrees and has moved this requirement in the final rule to
Sec.  192.620(b) as one of the criteria for determining when an
existing pipeline can be operated at alternative MAOP.
Section 192.328(c), Depth of Cover
    Three pipeline operators supported the proposed depth of cover
requirements, although one would clarify that they apply to new
construction. Another operator suggested that allowance be made for
less depth of cover if alternative means of protection are used (e.g.,
concrete slabs) that offer equivalent protection.
Response
    PHMSA agrees that alternative protection is acceptable and has
revised its proposed rule accordingly in this final rule. To satisfy
the rule, alternative protection must provide equivalent protection and
the operator must demonstrate this equivalence. Simply providing
barriers without demonstrating that they provide equivalent protection
is not sufficient.
    PHMSA did not intend this requirement to apply to new construction
only and thus, has not changed the requirement in the final rule. PHMSA
considers that a pipeline to be operated at alternative MAOP, including
existing pipelines, must have superior protection from outside force
damage. PHMSA recognizes that existing pipelines constructed in
compliance with Sec.  192.327 may have less cover than required in this
rule. Operators of those pipelines desiring to implement alternative
MAOP must provide equivalent protection for those segments not meeting
the depth of cover requirements.
Section 192.328(d), Initial Strength Testing
    A number of commenters objected to the proposed requirement that
any failure indicative of a fault in material disqualifies a pipeline
segment from operation at an alternative MAOP. The commenters suggested
that a root cause analysis be permitted, consistent with previously-
issued special permits, to determine if the fault indicates a systemic
issue. Disqualification is only appropriate, according to the
commenters, if a systemic issue exists, and failures can result from
isolated causes. One operator would also clarify that these
requirements apply to base pipe material rather than flanges, gaskets,
etc. Another suggested that multiple test failures can actually be
beneficial, because they prompt additional failure analyses that better
assure the integrity of the non-failed pipe.
Response
    PHMSA agrees that a single failure can reflect an isolated cause
and should not disqualify an entire segment from operation at an
alternative MAOP if it can be demonstrated that the failure is not
indicative of a problem that could affect the rest of the pipeline
segment. PHMSA has revised the final rule to allow a root cause
analysis of any failures as a way of justifying qualification of a
pipeline segment. Root cause analysis must demonstrate that failures in
alternative MAOP pipeline segments are not systemic. Operators are
required to notify PHMSA of the results of their evaluations, which
will allow us to validate their conclusions.
Section 192.328(e), Cathodic Protection
    INGAA and seven pipeline operators suggested that this paragraph be
deleted, since it duplicates requirements in Sec.  192.455. One of the
operators further commented that whether cathodic protection was
operational within 12 months becomes irrelevant once the line is
assessed and its condition is known.
Response
    PHMSA recognizes that Sec.  192.455 requires that cathodic
protection be operational within 12 months of placing a pipeline in
service but does not consider the requirement in this rule duplicative.
Operators who complied with Sec.  192.455 will, of course, meet this
criterion for operation at alternative MAOP. Those who did not install
cathodic protection within 12 months of initial operation will not,
whether or not Sec.  192.455 was effective at the time. PHMSA considers
it critical that cathodic protection be provided as quickly as possible
after construction, because there are some forms of corrosion that can
result in high corrosion rates (e.g., microbiological corrosion and
corrosion from current

faults) producing significant loss of pipe wall in a short period of
time. Operation at alternative MAOP is thus not allowed for those
pipelines for which cathodic protection was not provided within 12
months of initial operation.
    PHMSA has moved this requirement from Sec.  192.328, a section
addressing construction requirements, to Sec.  192.620(d)(8), a section
addressing operations and maintenance requirements. PHMSA believes that
this change will help emphasize that this is not simply a re-statement
of the requirement in Sec.  192.455.
Section 192.328(f), Interference Currents
    Three pipeline operators supported the proposed requirements in
this subparagraph (one with the understanding that Sec.  192.473 will
govern for an existing Class 1 pipeline). Taking a contrary position,
another operator urges PHMSA to delete this paragraph because the
requirement is already addressed in the regulations and it is difficult
to address all interference issues during construction without active
cathodic protection (cathodic protection is not required to be in
service until 12 months after construction).
Response
    It is important to address the potential for interference currents
as early as possible. Some pipelines have experienced significant wall
loss in the first months of operation due to the effect of interference
currents. While it may be true that all interference currents cannot be
identified before cathodic protection is in operation, many can be
anticipated and remediated during construction. These include the
effects of electric transmission lines or electrified trains sharing or
paralleling a right of way, or other ground beds in proximity to the
pipeline's route. Operators need to address, during construction,
interference currents that can be anticipated. Review of cathodic
protection effectiveness once it is in operation may identify
additional issues, and operators need to deal effectively with these.
It is not necessary, however, and potentially deleterious to pipeline
integrity to delay all actions addressing interference currents until
this time. The provisions proposed in the NPRM remain unchanged in the
final rule.

C.2.4. Eligibility for and Implementing Alternative MAOP

Section 192.620(a), Calculating an Alternative MAOP
    Most commenters from the pipeline industry objected that the
proposed requirements for calculating an alternative MAOP did not
recognize that class locations may change once a pipeline is in
service. They noted that Sec.  192.611 recognizes this for conventional
MAOP pipelines, and allows operation following a class change at a
higher MAOP than would be required for new pipe in that class provided
that testing was performed at a sufficiently high pressure. The
commenters sought similar treatment for alternative MAOPs in this
paragraph and conforming changes to the language in Sec.  192.611
concerning class location changes. These commenters also noted that the
proposed rule does not explicitly address compressor stations, meter
stations, etc.
    Two pipeline operators would reduce the test factor for Class 2
locations from 1.5 to 1.25. They contended that this would allow
testing of Class 1 and 2 pipelines to be done together, thereby
minimizing environmental disruption that would be associated with
separately testing Class 2 to a higher factor. They noted that testing
of both classes together would not be possible with a specified test
factor of 1.5 for Class 2, since this would overstress the Class 1 pipe
(i.e., exceed 100 percent SMYS).
    One operator suggested allowing a test factor of 1.25 for existing
pipelines and requiring 1.5 only for lines installed after the
effective date of this rule. They contended that specifying 1.5 as a
design factor for Class 2 results in the alternative MAOP for Class 2
pipe segments being less than currently allowed for existing pipelines.
    Two operators suggested that PHMSA amend the proposed rule to
explicitly state that the design factors will increase for facilities
(stations, crossings, fabricated assemblies, etc.) upgraded in
accordance with the rule. One suggested stating that an increase of
approximately 11 percent is allowed. The other suggested specific
design factors of 0.56 for station pipe, 0.67 for fabricated assemblies
and uncased road/railroad crossings in Class 1 areas, and 0.56 for such
assemblies/crossings in Class 2 locations.
    The state pipeline safety regulatory agency commented that the rule
should contain only one provision regarding the test pressure used in
determining the MAOP. This commenter noted proposed Sec.
192.620(a)(2)(ii) limits MAOP to 1.5 times the test pressure in Class 2
and 3 locations and that proposed Sec.  192.620(c)(3) allows 1.25 times
test pressure in all classes. The commenter contends that a reference
in the latter requirement to the former creates a confusing
circularity.
Response
    PHMSA agrees that the proposed regulation could be more restrictive
than existing requirements in Sec.  192.611 in the event of a class
change. As noted in the comments, the existing regulation allows
operation at a higher MAOP following a class change (i.e., higher than
would be required for a new pipeline installed in that class location)
provided that testing has been conducted at a sufficiently high
pressure to demonstrate adequate safety. PHMSA has revised the final
rule to be more consistent with Sec.  192.611 in allowing operation at
a higher pressure following a class change.
    PHMSA has reduced the required test pressure for existing pipelines
(i.e., pipelines installed prior to the effective date of the rule) in
Class 2 locations to 1.25 times MAOP. This is consistent with Sec.
192.611(a)(1). However, if Class 2 pipeline is tested at 1.25 times
MAOP, then operation at an increased alternative MAOP following a class
change is not allowed. Such testing does not provide sufficient
assurance of safety margin for the higher population Class 3 areas.
Operators who desire to operate at higher pressures following a change
from Class 2 to Class 3 must test their pipe at 1.5 times alternative
MAOP.
    PHMSA has included alternate design factors for existing facilities
and fabricated assemblies to be operated at alternative MAOP. PHMSA
does not agree that design factors for facilities and fabricated
assemblies are needed for new installations (i.e., those constructed
after the effective date of this final rule). PHMSA expects design
factors for new facilities (stations, crossings, fabricated assemblies,
etc.) to be in accordance with Sec.  192.111(b), (c), and (d).
Section 192.620(b), When may an alternative MAOP be used?
    Proposed paragraph b(6) limited eligibility for an alternative MAOP
for pipeline segments that have previously been operated to those that
have not experienced any failure during normal operations indicative of
a fault in material. A number of commenters objected to this
limitation, which is similar to the limitation in proposed Sec.
192.328(d) described above. Here, again, the commenters indicated that
root cause analysis should be allowed and operation at an alternative
MAOP

should be proscribed only if the evaluation reveals a systemic issue.
    GPTC requested that paragraph b(3) be clarified. That paragraph
requires that segments to be operated at alternative MAOP must have
remote monitoring and control provided by a supervisory control and
data acquisition system. GPTC requested that PHMSA clarify the degree
of ``control'' that is required and questioned whether remote control
of flow and pressure are required or if remote control of valves is all
that was intended.
    One pipeline operator requested that either this paragraph or
existing Sec.  192.611 be revised to clarify the applicability of the
current 72/60/50 percent SMYS limitation on hoop stress. The operator
believes it is unclear when and if the Sec.  192.611 limitations on
hoop stress apply if an alternative MAOP is used.
Response
    PHMSA agrees that exclusion from operation at an alternative MAOP
is appropriate only if a failure during mill hydrostatic testing,
construction hydrostatic testing, or operation is indicative of a
systematic issue. PHMSA has revised the final rule here (in this
paragraph and in Sec.  192.328(d) above) to allow root cause analysis
with operators required to notify PHMSA of the results.
    Control requires that operators monitor pressures and flows as well
as compressor start-up and shut-down. Valves must also be able to be
remotely closed. The final rule has been modified to make these
requirements clear.
    PHMSA has revised Sec.  192.611 to include hoop stress limits
applicable to pipeline operating at alternative MAOP.
Section 192.620(c), What must an operator do to use an alternative
MAOP?
    INGAA and four pipeline operators suggested that an engineering
analysis should be allowed for existing pipe that was not tested to 125
percent of the alternative MAOP. They noted that some existing pipe may
have been tested to higher pressures but not quite to 125 percent, and
that this pipe should not be automatically excluded. They noted that
experience shows that the vast majority of existing pipe is tested
successfully without systemic problems, and that the allowance for 95
percent vs. 100 percent of girth weld examinations in proposed Sec.
192.328(b)(2) establishes a precedent for allowing existing pipe that
can not fully meet new pipe criteria to operate at an alternative MAOP.
    One pipeline operator suggested that the rule either state that
pressure test must be at 125 percent of alternative MAOP for Classes 1,
2, and 3 or be revised to refer to the factors in Sec.
192.620(a)(2)(ii). They contended the proposed language was unclear as
to whether 125 percent is sufficient in all class locations.
    A state pipeline safety regulatory agency again suggested that the
rule should contain only one provision regarding test pressure (see
discussion under Sec.  192.620(a) above).
    Several commenters addressed training and qualification
requirements in proposed Sec.  192.620(c)(5). The state agency noted
that they duplicated proposed Sec.  192.328(a)(2)(ii) and essentially
applied operator qualification (OQ) requirements (subpart N) to
construction personnel. The state agency suggested it would be simpler
and less confusing if it were done in subpart N. One pipeline operator
also suggested deleting paragraph c(5) and referring to subpart N. This
operator noted that the proposed rule used undefined and vague
language--terms such as QC and integrity verification (which could be
confused with assessments under subpart O). The operator further noted
that subpart N requires OQ and that the meaning of its requirements is
well known.
    GPTC requested clarification that the requirements are only
applicable to segments that operate at an alternative MAOP and as to
the meaning of the term ``integrity verification method.''
Response
    PHMSA does not agree that an engineering analysis provides an
adequate basis to justify operation at alternative MAOP. Operators who
desire to use an alternative MAOP for existing pipelines that were not
tested to sufficient pressures should re-test their pipelines.
    PHMSA has revised the final rule to refer to paragraph (a) for test
pressures rather than duplicating them. PHMSA agrees that this change
could help avoid confusion.
    PHMSA agrees that applying the known requirements of subpart N,
related to the qualification of personnel performing work on the
pipeline, would likely cause less confusion than specifying the
alternative, but similar, requirements included in the proposed rule.
Pipeline operators are familiar with subpart N, and their training
programs under that subpart have been subjected to audits by PHMSA or
states, as appropriate. By its terms, though, subpart N does not apply
to construction tasks, since they are not ``an operations or
maintenance task''--one part of the four-part test in Sec.  192.801(b).
PHMSA has revised this final rule to provide that ``construction''
tasks associated with implementing alternative MAOP be treated as
covered tasks notwithstanding the definition in Sec.  192.801(b). For
those tasks, then, the requirements of subpart N will apply. This
change obviates the concerns expressed by GPTC and the state agency.
(PHMSA disagrees with the state comment, however, that the requirement
as proposed duplicated Sec.  192.328(a)(2)(ii), as the latter
requirement applied only to girth weld coating and not to all
construction-related tasks.)

C.2.5. Operation and Maintenance Requirements

Section 192.620(d), Additional O & M Requirements
    Two pipeline operators and one state pipeline regulatory agency
suggested that covered pipelines should be held to the same
requirements as pipelines in HCA under subpart O. They believe that
this would make most of Sec.  192.620(d) unnecessary and would increase
flexibility for operators.
    The state regulator noted that it would avoid confusion that might
be created for covered pipelines that would be subject to both sets of
requirements. One operator commented that no technical basis is
provided for the proposed requirements, while subpart O is based on
science and research.
Response
    PHMSA disagrees with these comments and has not changed the final
rule because some provisions are more restrictive than subpart O.
Section 192.620(d)(1), Identifying Threats
    INGAA and three pipeline operators suggested eliminating the
requirement for a threat matrix and the implied need for additional
preventive and mitigative measures. They noted that operation at
incrementally higher pressures does not inherently increase risk or
introduce new threats and that the proposed rule already includes
requirements sufficient to address the incremental change.
Response
    PHMSA does not agree that the rule necessarily addresses all
threats to a pipeline. The rule addresses many known threats; however,
other threats may exist or develop that may affect the pipeline's
integrity. It is up to the operator to identify and evaluate possible
pipeline threats and therefore PHMSA retained the requirement to
identify and evaluate threats consistent with Sec.  192.917. The term
``assess'' was changed to ``evaluate'' to avoid

confusion with a similar term used in integrity management.
Section 192.620(d)(2), Notifying the Public
    INGAA and five pipeline operators would eliminate the requirements
in this proposed section. They contended they are unnecessary as they
duplicate requirements in existing Sec.  192.616 for public education.
They further contended that a dedicated notification, specific to
operation at a higher pressure, is not needed. One operator would
delete subparagraph (d)(2)(ii) and replace it with a one-time
notification before operation under an alternative MAOP begins. This
operator believes that the proposed requirement for a continuing
information program is excessive, but that a one-time notification
could be appropriate.
Response
    Because of the higher consequences of operating a pipeline at a
higher alternative MAOP (and thus a greater impact radius), PHMSA
believes that additional public information is necessary to inform any
stakeholders living along the right-of-way of this increase. Where the
alternative MAOP pipeline is in an HCA already identified per Subpart
O, then no additional notification is necessary beyond what is already
required.
Section 192.620(d)(3), Responding to an Emergency in High Consequence
Areas
    Most industry commenters suggested deleting the requirement that
operators be able to remotely open mainline valves. They maintained
this requirement is unnecessary as an emergency response measure and is
contrary to the operating practice of many gas transmission pipeline
operators. Some also opposed a requirement for remote pressure
monitoring, indicating that it would be costly to provide and would add
no value. AGA commented that the language relating to remote control of
valves was too prescriptive and could have the unintended consequence
of requiring operators to make their safety procedures less stringent
(presumably by allowing remote opening of valves).
    GPTC and two pipeline operators questioned the requirement for
remote valve operation if personnel response time to the valves exceeds
one hour. They argued that the one-hour criterion is arbitrary and not
justified by research. One operator suggested that it is also counter
to experience. These commenters also noted that it is unclear how the
response time is to be applied, from the time of notification of an
event, from the time a responder is requested to go to the valve
location, or from some other triggering event. GPTC suggested that
PHMSA consider a requirement based on mileage, similar to Sec.
192.179. One operator indicated that the need for remote control should
be based on risk analysis rather than an arbitrary specified response
time.
Response
    PHMSA agrees that the proposed requirement that operators be able
to remotely open mainline valves is not needed for emergency response.
PHMSA agrees that it is more conservative to require local action to
open valves that may have been closed in response to an emergency.
PHMSA has modified the final rule to eliminate the requirement that
operators be able to remotely open valves. PHMSA considers it important
to be able to monitor pressure in order to know that valve closure has
been effective. PHMSA has retained this requirement.
    PHMSA considers a one-hour response time appropriate and
reasonable. It provides time to respond to events while limiting the
consequences of an extended conflagration. In the final rule, PHMSA has
clarified that the one-hour period begins from the time an event
requiring valve closure is identified in the control room and is to be
determined using normal driving conditions and speed limits.
Section 192.620(d)(4), Protecting the Right-of-way
    All commenters except the state pipeline safety regulatory agency
and the steel/pipe manufacturers addressed this section. All contended
that the requirement to patrol the right-of-way 26 times per year was
excessive and that experience indicates that more frequent patrolling
does not prevent pipeline events. They maintained that the proposed
frequency has no apparent basis other than that it is the patrolling
frequency required for hazardous liquid pipelines and that application
of a hazardous liquid pipeline frequency to gas transmission lines is
inappropriate.
    One operator noted that its experience with monthly patrols has
demonstrated that there is very little excavation activity during
winter and the summer growing season, making patrols then of little
value. The commenters' proposals for alternate patrolling intervals
varied, with some suggesting intervals that would vary based on the
class location. INGAA suggested patrolling every 4\1/2\ months and
after known events.
    INGAA and one pipeline operator suggested deleting the requirement
for a soil monitoring plan, because it would be costly and only
duplicates other existing requirements.
    INGAA and six pipeline operators suggested deleting the requirement
to maintain depth of cover. In its place, they would require restoring
depth of cover or providing appropriate preventive and mitigation
measures only where damage may occur due to loss of cover. They noted
that maintaining the original depth of cover is impractical and
unnecessary. Normal erosion and other events can reduce depth of cover,
but that reduction does not necessarily lead to an increased risk of
damage. Action may be needed in limited circumstances and providing
other protection in those circumstances may be more effective and less
costly than restoring the original depth of cover. One operator
suggested that a monitoring/maintaining depth of cover requirement
should be driven by events or risk analysis and that discussion in the
preamble of the NPRM implied such an approach. This operator suggested
allowing engineered solutions in addition to restoring depth of cover.
    INGAA and four pipeline operators would delete or relax the
requirement for line-of-sight pipeline markers. INGAA noted that
discussion at the March 2007 public meeting indicated that such markers
add no value. One operator suggested that it would be more effective to
emphasize one-call damage prevention in the preamble of the final rule.
Another operator noted that installation of such markers is ``non-
trivial,'' and that there is no data or analysis supporting the need
for them. Yet another operator commented that the intent of the
requirement is unclear and suggested that circumstances other than
agricultural areas and large bodies of water (exclusions included in
the proposed rule) would also make it difficult to install line-of-
sight markers (e.g., steep terrain, swamps).
    INGAA and five pipeline operators objected to what they
characterized as an ``open ended'' requirement to implement national
consensus standards for damage prevention. These commenters suggested
that the requirements focus on the damage prevention best practices
identified by the Common Ground Alliance (CGA) and require that
operators implement the CGA best practices that apply to their
situation. One operator suggested that operators be allowed to evaluate
and choose among CGA practices. Another operator also supported a right
to choose, indicating that the CGA guide includes no expectation that
operators will adopt all best practices.

    INGAA and five pipeline operators objected to the proposed
requirement for a right-of-way management plan, because it duplicates
existing requirements for damage prevention.
Response
    PHMSA has revised the required patrol frequency to once per month,
at intervals not to exceed 45 days. The decision to reduce the
patrolling frequency from 26 patrols per year was based on further
analysis of the value added by the cost of additional patrolling,
PHMSA's greater experience with administering special permits, and
comments from industry and public advocates supporting risk-based
requirements rather than a one-size-fits-all approach. PHMSA believes
that the right of way management plan required by Sec.
192.620(d)(4)(vi), coupled with the patrolling requirement, will
provide appropriate safety coverage through requiring an operator to
develop and implement an array of actions based on the risk of third-
party damage to the pipeline. These preventative actions may well
include additional patrolling above what is required by this rule in
areas that are more heavily-populated or that possess greater chances
for third-party activities in the vicinity of a pipeline.
    PHMSA has retained the requirement for a soil monitoring program.
Gas transmission pipelines are often located in areas that can exhibit
unstable soils, such as clay, hills, and mountainous areas. It is
important to assure that stresses caused by soil movement do not damage
pipelines in these areas with reduced design safety factors. PHMSA
recognizes that operators may already address these issues in their
damage prevention plans or other operating and maintenance procedures.
If so, an additional plan is not required. Operators must be able to
demonstrate, during regulatory audits, that soil monitoring is
addressed within their procedures.
    PHMSA has retained the requirement for line-of-sight pipeline
markers. Outside damage is the most significant threat to gas
transmission pipelines, resulting in the greatest number of accidents.
These accidents occur despite current requirements for pipeline
markers. Those requirements in Sec.  192.707 already require that
markers be maintained ``as close as practical'' in the areas required
to be covered. PHMSA continues to believe that it is important to
provide line-of-sight markers for pipelines operating at alternative
MAOP in order to reduce the frequency of outside damage. PHMSA supports
one-call programs, and regularly takes actions to encourage and foster
their use. Still, damage incidents occur. It is important to reinforce
the need for using a one-call program by providing visual evidence that
a pipeline is located in an area subject to potential excavation.
    At the same time, PHMSA recognizes that installation of line-of-
sight markers is not feasible in all locations. The rule does not
require installation of line-of-sight markings in agricultural areas or
large water crossings such as lakes and swamps where line-of-sight
markers are not practicable. The marking of pipelines is also subject
to FERC orders or environmental permits and local laws/regulations. The
rule does not require installation where these other authorities
prohibit markers.
    PHMSA also retained the requirement for a right-of-way management
plan since PHMSA data indicates recurring similarities in pipeline
accidents on construction sites where better management of the right-
of-way could have prevented the accidents. This provision is not
redundant with existing damage prevention program requirements, but
requires operators to take further steps to integrate activities under
those programs to provide for better protection of the right-of-way.
Section 192.620(d)(5), Controlling Internal Corrosion
    INGAA, GPTC, four pipeline operators and the state pipeline safety
regulatory agency would require a program to monitor gas quality and to
remediate internal corrosion as needed but would delete all the
specific requirements in this section. One operator suggested that a
program complying with Subpart I is all that is needed. The state
regulatory agency noted that the NPRM provided no rationale for more
stringent or prescriptive requirements than those recently published as
Sec.  192.476.
    Two pipeline operators objected to the requirement for filter
separators, contending that these devices are not effective for dealing
with upsets involving free water and can provide a false sense of
security. One suggested that other actions could be required to assure
gas quality. Two other operators suggested that properly designed gas
separators would be as effective as filter separators.
    One operator objected to requirements for cleaning pigs,
inhibitors, and sampling of accumulated liquids. Another opposed the
requirement for inhibitors. These operators noted that these actions
are not needed if gas monitoring confirms no deleterious constituents.
They maintained that the requirements are unnecessary and can
potentially result in unintended consequences and risks.
    AGA contended that operators should be allowed to determine
appropriate methods for monitoring gas quality and that these methods
need not always require testing by individual operators. AGA believes
this is especially true if tariffs and operating experience demonstrate
the absence of contaminants. One pipeline operator asked that PHMSA
clarify that the required chromatographs are for analysis of corrosive
constituents and need not provide complete analysis for heating value
or other purposes.
    Two pipeline operators suggested that PHMSA define deleterious gas
stream constituents of concern. Two pipeline operators suggested that
the limits on gas constituents should be deleted or revised based on
research and testing. They believe that the proposed limits are not
technically justified. One further noted that deleterious effects may
result from contaminants acting ``in concert.''
    One pipeline operator would revise the requirement for review of an
operator's internal corrosion monitoring and mitigation program to
annual review because there is no technical justification for quarterly
reviews. Another operator suggested that the gas quality requirements
be deleted, as they may conflict with tariffs and result in duplicate
enforcement. This operator also suggested that sampling intervals be
established by reference to section Sec.  192.477 and agreed that a
requirement for quarterly review of internal corrosion monitoring
programs is excessive.
Response
    PHMSA concludes that the proposed requirements do not duplicate or
conflict with those in the recently published Sec.  192.476. The latter
requirements deal principally with design considerations related to
internal corrosion, while those included here address monitoring to
determine whether conditions conducive to such corrosion occur.
Similarly, Sec.  192.477 only requires monitoring if corrosive gas is
present. The requirements included here specify contaminants to be
monitored and limits to be achieved. Since Sec.  Sec.  192.476 and
192.477 represent the requirements in subpart I related to internal
corrosion, PHMSA does not agree that a program complying with subpart I
alone is sufficient.
    PHMSA has revised the requirement for use of cleaning pigs,
inhibitors, and collection of accumulated liquids to apply only in
those situations in which corrosive gas is determined to be

present. For the particular case of hydrogen sulfide, PHMSA has
specified a limit (0.5 grain per hundred cubic feet, 8 parts per
million (ppm)) above which this requirement applies.
    PHMSA has retained the requirements for gas monitoring. It is
important to monitor the gas stream to assure that internal corrosion
will not occur or will be identified if corrosion does occur.
Continuous monitoring is the most effective way of doing this. PHMSA
agrees that monitoring equipment required by this rule is for the
purpose of analyzing corrosive gas constituents and need not provide
estimates of heating value or other characteristics. Operators can rely
on others (e.g., those supplying gas to them) to perform monitoring,
but they must assure that such monitoring covers all gas streams and
meets the requirements of this rule, including the need for continuous
monitoring. PHMSA has also retained the requirement to review the
internal corrosion monitoring program quarterly. Such reviews are
needed to help assure that upset conditions that could potentially
cause internal corrosion are identified and addressed promptly. Annual
reviews are insufficient to do this.
    PHMSA has revised the limit for hydrogen sulfide to 1.0 grain per
hundred cubic feet, or 16 ppm. (PHMSA has also presented this limit in
both forms of measurement, as suggested by one commenter). This limit
is more consistent with typical tariff limits. At the same time, the
final rule requires that additional mitigative actions, including use
of cleaning pigs and inhibitors be required when the hydrogen sulfide
content exceeds 0.5 grain per hundred cubic feet, as this concentration
increases the likelihood of internal corrosion.
    The final rule clarifies that deleterious gas stream constituents
also include entrained or suspended solids (regardless of size) that
are detrimental to the pipeline or pipeline facilities.
Section 192.620(d)(6), Controlling Interferences That Can Impact
External Corrosion
    Two pipeline operators requested that we clarify that interference
surveys are only required where interference is likely, are to be
developed using operator judgment, and can be performed using voltage
measurements versus ``current.''
Response
    PHMSA has clarified the final rule to require that surveys be
performed in areas where interference is suspected. Operators should
consider the proximity of potential sources of interference, including
electrical transmission lines, other cathodic protection systems,
foreign pipelines, and electrified railways in deciding where surveys
are needed. Operators must conduct surveys capable of detecting the
effect of interfering currents, but these surveys need not measure
``current'' directly.
Section 192.620(d)(7), Confirming External Corrosion Control Through
Indirect Assessment
    INGAA and four pipeline operators requested that this section be
revised to require close interval survey (CIS) alone versus one of CIS,
direct current voltage gradient (DCVG), or alternating current voltage
gradient (ACVG). One of these operators requested clarification that
indirect examination is not necessary if additional measures are taken
to assure the integrity of the pipeline. Yet another operator suggested
that this section be revised to allow other methods of indirect
assessment, noting that C-SCAN (which is a current measurement
technique) is one possibility that appears to be precluded by the
proposed language. All of these commenters plus three additional
pipeline operators requested that the timeframe for conducting these
examinations be relaxed from six months to one year. They noted that
six months may often be impractical because of limitations associated
with seasonal weather.
    One pipeline operator would delete the proposed requirement for a
coating survey of existing pipelines, maintaining that this examination
is not needed, since the results of ILI and CIS show that the
combination of coating and cathodic protection is working to protect
against corrosion. This operator would move the requirement for
indirect survey and coating damage remediation to Sec.  192.328 to make
it clear that this is a construction requirement applicable to new
pipelines only. Another operator also commented that requirements to
remediate construction damaged coating should be limited to new pipe
only. This operator further requested deleting the proposed requirement
to repair all voltage drops classified as moderate or severe by
National Association of Corrosion Engineers (NACE), since it is
unnecessary and impractical to repair every voltage drop. Another
operator commented that operators should be allowed to develop specific
repair criteria based on their experience.
    INGAA and four pipeline operators would relax the proposed
requirement to remediate construction coating damage to require either
remediation or appropriate cathodic protection. They suggested that the
proposed requirement conflicts with the NACE standard referenced in
this section (NACE RP-0502-2002) and that coating remediation is not
needed as cathodic protection provides adequate protection for areas
affected by coating holidays. Another operator noted that the NACE
defect classification guidelines are qualitative and that
interpretation differences could result in differing repair
expectations.
    INGAA and two pipeline operators recommended relaxing the
requirement to integrate indirect assessment results with ILI from six
months to one year. They believe that more rapid integration is not
needed and that the value of quicker integration is not explained in
the NPRM. Another operator suggested there is an inconsistency in that
paragraph (ii) requires action based on the results of one assessment
while paragraph (iii) requires that the results of two assessments be
integrated.
    INGAA and three pipeline operators would delete the periodic
assessment requirements of proposed paragraph (iv). They would move the
requirements for location of CIS test points in proposed subparagraph
(B) to Sec.  192.328, as they contended these are more appropriate as
construction requirements. These commenters would further revise the
CIS location requirements to state that a CIS test station must be
within one mile of each HCA, versus within each HCA. They contended
that it is not practical to require a test station within each HCA,
noting that the length of the pipeline in some HCAs may be very short.
Another operator would combine subparagraphs (A) and (B).
Response
    CIS is a technique to locate areas of poor cathodic protection and
is considered a macro tool. Micro tools, such as DCVG or ACVG, must be
used to locate small but critical coating holidays. C-SCAN, which is a
current measurement technique, is considered a macro tool and will only
find large coating holidays. Small coating holidays can be just as
critical as large ones, especially in areas where cathodic protection
potentials can be depressed. PHMSA considers it important to monitor
coating condition. The comments suggesting that macro tools be allowed
appear to be based on the premise that small coating holidays are not
important as long as cathodic protection continues to protect the
pipeline. As discussed above, PHMSA does not agree with this
presumption, and here, again, does not agree that

either coating or cathodic protection is required; both are needed.
PHMSA recognizes that if one accepts the presumption that assuring
coating integrity is not important on pipelines subject to cathodic
protection, then prompt resolution of coating issues is not important
either. Since PHMSA does not accept the premise, PHMSA has not relaxed
the proposed timeframes for conducting surveys or integrating results.
    In particular, PHMSA does not agree that a one year interval should
be allowed to assess coating adequacy. Experience has demonstrated that
significant corrosion can occur during very short intervals. PHMSA
notes that the proposed requirement potentially extends the period
between the beginning of pipeline operation and coating assessment to
18 months--12 months after operation in which cathodic protection must
be made operational (Sec.  192.455(a)(2)) plus the six months allowed
here. PHMSA considers this to be the maximum period that should be
allowed before determining coating adequacy. Proper planning and
scheduling should allow operators to accommodate weather and other
scheduling concerns. Operators can delay the start of operation at an
alternative MAOP if they cannot schedule coating surveys within six
months.
    PHMSA's conclusion that coating integrity is important, regardless
of the presence of cathodic protection, means that determining coating
adequacy is important for existing pipelines as well as new
construction. As such, it is not appropriate to move this requirement
to a section applicable to new construction only. Further, it is not
acceptable to rely on ILI or other assessment methods to identify
corrosion after it has occurred. The purpose here is to prevent
corrosion. ILI or other assessments are a second level of defense,
detecting corrosion after it occurs, but PHMSA does not consider them
to obviate the need for actions to prevent the problem from occurring
in the first place. CIS is a verified method of determining if all of a
segment is protected by appropriate cathodic protection potentials. The
use of CIS will allow an operator to find any ``hot spots'' along the
pipeline that could cause active corrosion. The CIS will find any
depressed locations whereas a test station survey may miss such
locations unless they are in close proximity to the test station.
    With respect to proximity to a test station, PHMSA agrees that
there could be situations in which it may not be practical to locate a
test station within an HCA. This could occur, for example, when the HCA
is determined by an identified site near the outer radius of the
potential impact circle, in which case the length of pipeline in the
HCA could be very short (on the order of several feet). Still, PHMSA
does not agree that this limitation should be addressed by requiring
that a test station be within one mile of an HCA. PHMSA has revised the
final rule to require that a test station be located within an HCA if
practicable and has retained the proposed requirement that test
stations be located at half-mile intervals on pipelines to be operated
at alternative MAOP.
Section 192.620(d)(8), Controlling External Corrosion Through Cathodic
Protection
    INGAA, GPTC and eight pipeline operators considered the requirement
to address inadequate cathodic protection readings in six months to be
excessive. They also noted that seasonal and land use issues make
responding within one year much more reasonable, and suggested the
proposed rule be changed accordingly. GPTC and one operator noted that
the proposed change is inconsistent with an existing PHMSA
interpretation, which states that remediation of inadequate cathodic
protection readings is required before the next scheduled monitoring.
The operator noted that this is typically one year (not to exceed 15
months), supporting the proposed change to a one-year response in this
rule.
    INGAA and three pipeline operators objected to the proposed
requirement to conduct CISs after remediating cathodic protection
problems to evaluate effectiveness. They noted that a CIS is not needed
to confirm resolution of many problems (e.g., loss of power, cut cable,
short). They agreed that operators should confirm that remedial action
was appropriate and effective, but contended that a requirement to
perform a CIS after any remedial action is unjustified and excessive.
Response
    As discussed above, experience has shown that significant corrosion
damage can occur over brief periods. Pipelines operating at an
alternative MAOP have less margin for corrosion than do pipelines
operating at MAOP determined in accordance with Sec.  192.111. Cathodic
protection is an important protection against corrosion damage, as
recognized by those commenting on this rule. PHMSA does not agree that
it is acceptable to wait one year to resolve known cathodic protection
problems. At the same time, PHMSA recognizes that there may be
situations in which remediation in six months is not practical. PHMSA
has revised the final rule to require operators to notify the PHMSA
Regional Office where a pipeline is located (and states where
appropriate) if inadequate cathodic protection readings are not
addressed within six months, providing the reason for the delay and a
justification that the delay is not detrimental to pipeline safety.
This will allow regulators to review the circumstances of each
situation in which resolution takes longer than six months and to make
a judgment of adequacy based on the particular circumstances.
    PHMSA agrees that it is not necessary to perform a complete CIS
again to verify that any remedial action has addressed an identified
problem. Commenters are correct in noting that problems such as a cut
cable or short can result in inadequate cathodic protection readings
and that correction of these problems can be verified without a new
CIS. PHMSA has revised the final rule to require that operators verify
that corrective action is adequate, leaving the means to do so up to
the operator's discretion and judgment.
Section 192.620(d)(9), Conducting a Baseline Assessment of Integrity
    Proposed Sec.  192.620(d)(9)(iii) would require that headers,
mainline valve by-passes, compressor station piping, meter station
piping, or other short portions that cannot accommodate ILI tools be
assessed using DA. INGAA and four pipeline operators objected to this
requirement as unjustified and inconsistent with previous special
permits. They suggested a change that would also allow pressure testing
or development and implementation of a corrosion control plan. They
further noted that these segments may be designed to Sec.  192.111, may
not operate at an alternative MAOP, and thus may not be subject to this
section.
    One operator also noted that there may be portions of a pipeline
facility that will not be operated at an alternative MAOP. The operator
requested clarification that the proposed requirements apply only to
segments that are intended to operate at an alternative MAOP. This
commenter also suggested an exclusion for small pipe and equipment to
be consistent with a frequently asked question (FAQ) 84 on the
gas transmission integrity management Web site (http://
primis.phmsa.dot.gov/gasimp/). (The FAQ addresses whether small-
diameter piping, e.g., within a compressor station, must be considered
to be part of an HCA. It states that potential impact

radii should be calculated, and a determination made as to whether an
HCA exists, based on the diameter of individual pipeline segments.)
    The same operator would also allow the baseline assessment for an
existing pipeline segment to be conducted before operation at an
alternative MAOP begins but within the assessment interval specified in
subpart O rather than the proposed two years. The operator contended
that there is no scientific basis to require assessments every two
years, particularly if a pipeline segment is being managed under
subpart O.
Response
    PHMSA agrees that assessment of small-diameter station piping can
be performed using pressure testing and has revised the final rule
accordingly. PHMSA does not agree that it is acceptable for such a non-
piggable pipeline to be under an unspecified corrosion control plan
rather than to be subject to assessment.
    PHMSA agrees that FAQ 84 addresses the same pipe, but does
not agree that it is a precedent for determining whether a small-
diameter pipeline requires assessment. An FAQ is advisory in nature and
this FAQ provides guidance in the context of integrity management, on
whether this pipeline should itself be determined to be an HCA. For
this rule, additional assessment requirements are being applied to a
pipeline operating at an alternative MAOP, regardless of whether it is
in an HCA. PHMSA has revised this paragraph to clarify that it applies
only to a pipeline operating at an alternative MAOP. Small-diameter
pipe within a station that does not operate at alternative MAOP would
not be affected by these requirements. PHMSA agrees that small-diameter
pipe, headers, meter stations, compressor stations, river crossings,
road crossings and any other pipeline facility can be designed and
constructed in accordance with Sec.  192.111 criteria and then would
not be subject to alternative MAOP integrity assessment criteria such
as ILI and DA.
    PHMSA does not agree that it is acceptable to rely on assessments
that may have been performed within the time intervals allowed by
subpart O. Under subpart O, it may have been nearly ten years (in some
limited cases 15 years) since a complete assessment was performed.
PHMSA considers that more current information is needed before deciding