Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines, 62148-62181 [E8-23915]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 73, Number 202 (Friday, October 17, 2008)]
[Rules and Regulations]
[Pages 62148-62181]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-23915]



[[Page 62147]]

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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

Federal Register / Vol. 73, No. 202 / Friday, October 17, 2008 / 
Rules and Regulations

[[Page 62148]]


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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 alan.mayberry@dot.gov.

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

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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

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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 https://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,

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     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

[[Page 62152]]

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

[[Page 62153]]

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.

[[Page 62154]]

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-

[[Page 62155]]

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

[[Page 62156]]

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 pl