[Federal Register Volume 73, Number 202 (Friday, October 17, 2008)]
[Rules and Regulations]
[Pages 62148-62181]
From the Federal Register Online via the Government Publishing 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 <a href="/cdn-cgi/l/email-protection#5839343936763539213a3d2a2a21183c372c763f372e"><span class="__cf_email__" data-cfemail="650409040b4b08041c070017171c25010a114b020a13">[email protected]</span></a>.

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

[[Page 62149]]

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:
    <bullet> 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.
    <bullet> High pressure hydrostatic testing is able to remove 
defects that may fail in service.
    <bullet> 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

[[Page 62150]]

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:
    <bullet> 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;
    <bullet> 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,

[[Page 62151]]

    <bullet> 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:
    <bullet> 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.
    <bullet> 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.
    <bullet> Bare or ineffectively coated pipe. This pipe lacks the 
coating needed to prevent corrosion and to make cathodic protection 
effective.
    <bullet> Pipelines with wrinkle bends. Section 192.315(a) currently 
prohibits wrinkle bends in pipeline operating at hoop stress exceeding 
30 percent of SMYS.
    <bullet> 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.
    <bullet> Pipe manufactured by certain processes, such as low 
frequency electric welding process.
    <bullet> 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 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)

[[Page 62157]]

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

[[Page 62158]]

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

[[Page 62159]]

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

[[Page 62160]]

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

[[Page 62161]]

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.

[[Page 62162]]

    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

[[Page 62163]]

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

[[Page 62164]]

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) <greek-i>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

[[Page 62165]]

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 <greek-i>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 
that it is acceptable to operate a pipeline at an alternative MAOP. 
PHMSA considers the two-year period reasonable for operators to 
schedule and perform assessments that will result in more current 
information when the operating stresses on the pipeline are increased.
Section 192.620(d)(11), Making Repairs
    INGAA and three pipeline operators noted that the repair 
requirements in the proposed rule are inconsistent with subpart O and, 
they believe, overly conservative and burdensome. INGAA contended that 
the proposed requirements will be unachievable in many cases. Another 
operator commented that the repair criteria proposed for Class 2 and 3 
areas are extremely conservative and unnecessary.
    Two pipeline operators suggested that this section be replaced with 
a reference to subpart O, since they believe the repair requirements of 
that subpart and ASME/ANSI B31.8S (referenced in subpart O) are 
appropriate for pipelines operating at 80 percent SMYS.
    Two pipeline operators noted that the dent repair criteria in 
subparagraph (i)(A) are those for new pipelines following construction 
and before commissioning and suggested that these are inappropriate for 
existing pipelines. One of these operators contended that the repair 
criteria for existing pipelines should be as in subpart O, Sec.  
192.933(d). The other noted that there is experience demonstrating that 
plain dents of much greater than two percent of pipe diameter in depth 
are not a threat to pipeline integrity.
    Three pipeline operators proposed alternative repair criteria. They 
would require immediate repair of defects for which the failure 
pressure is 1.1 times the revised alternative MAOP. They would require 
repairs within one year for defects for which the failure pressure is 
1.25 times the MAOP. They contended that these criteria are consistent 
with those in subpart O and ASME/ANSI B31.8S and are appropriate. They 
believe that the criteria in the proposed rule represent an 
inappropriate shortening of the time allowed to address identified 
defects.
    Proposed subparagraph (i)(A) would require that an operator ``use 
the most conservative calculation for determining remaining strength'' 
of a pipeline segment containing an identified anomaly. INGAA and four 
pipeline operators contended that this requirement could be interpreted 
to require that multiple calculations be performed, using all available 
tools/models, to determine which is most conservative. They believe 
this is inappropriate and that operators should use the most 
appropriate calculational tool.
Response
    PHMSA recognizes that the repair criteria in this rule are more 
stringent than those in subpart O. PHMSA considers this appropriate. A 
pipeline that will operate under alternative MAOP is subject to more 
stress and has less wall thickness margin to failure than most 
pipelines operating under subpart O (with the exception of some 
grandfathered lines). Most pipelines that will be subject to this rule 
will be new pipelines. PHMSA's repair criteria use safety factors 
similar to those for the design of a new pipeline based upon class 
location design factors, and are intended to maintain overall safety 
margins at corrosion anomalies based upon all operating and 
environmental factors. The net effect of the QA and O&M requirements in 
this rule for construction and operation of those pipelines covered by 
the rule will likely result in the need for few repairs, even with 
these stricter criteria. PHMSA considers these factors of safety a key 
element in assuring public safety on higher MAOP pipelines.
    Similarly, PHMSA disagrees that failure pressures of 1.1 and 1.25 
times MAOP are appropriate for immediate and one-year (respectively) 
repairs for all class locations. Class 2 and Class 3 locations require 
more stringent safety factors for anomaly evaluation and remediation 
due to the higher consequences to public safety that may be caused by a 
leak or rupture of the pipeline. As discussed extensively throughout 
this response to comments, pipelines to be operated at alternative MAOP 
will operate at higher pressures with less margin to failure than most 
pipelines. Use of repair criteria different from and requiring repairs 
quicker than in subpart O is appropriate.
    With respect to dents, the repair criteria of Sec.  192.309(b) 
apply only for dents found during construction baseline assessments 
(i.e., for new pipelines). PHMSA notes that this section already 
requires repair of two percent dents for pipelines over 12\3/4\ inches 
in diameter. The criteria for repairing dents on existing pipelines and 
subsequent assessments on new pipelines and existing pipelines are in 
Sec.  192.933(d).
    PHMSA acknowledges that an operator cannot know which method for 
calculating remaining strength is most conservative without applying 
each method. Questions have been raised concerning the applicability of 
some current methods for calculating the remaining strength of high-
strength pipelines and greater depth corrosion anomalies in all field 
operating

[[Page 62166]]

conditions. PHMSA is planning to sponsor a public meeting to review 
these questions and help determine the adequacy of existing 
calculational methods for the kind of high-strength pipe that will 
operate at alternative MAOP. PHMSA will propose changes to this rule at 
a later date, if appropriate.

C.3. Comments on Regulatory Analysis

    One pipeline operator submitted two comments relating directly to 
the regulatory analysis supporting the proposed rule.
    First, the operator contends that the expected reduction in 
expenditure for compressors for new pipelines should not be claimed as 
a benefit. The operator contended that reductions may be realized for 
existing pipelines that operate at an alternative MAOP but not for new 
pipelines.
    Second, the operator contended that PHMSA should not state that new 
design factors will result in increased capacity for new pipelines and 
noted that new pipelines will be designed for the required capacity. 
The effect of the proposed rule will be to reduce costs by allowing the 
use of thinner-walled pipe.
Response
    PHMSA understands that the operator's statement that new pipelines 
will be designed for the required capacity is at the heart of both of 
these comments. The operator essentially contended that new pipelines 
that will be so designed will see no increased capacity or change in 
costs as a result of this rule. PHMSA does not agree. New pipelines 
designed with alternative MAOPs should mean less cost to the customer/
public, and thus a benefit to society, due to less capital costs for 
the same natural gas through-put/flow volumes. Existing pipelines will 
be able to carry up to an additional 11 percent natural gas flow 
volumes based upon the overall design of the pipeline and compressor 
stations with this alternative MAOP.
    In the absence of this rule (or of obtaining a special permit to 
operate at alternative MAOP) new pipelines would need to be designed 
for less capacity or at increased cost (due to the need to use thicker-
walled pipe). Thus, there is a societal benefit to this rule in that it 
will allow more gas to be transported at a higher standard of safety 
for a given dollar investment. The companies designing and constructing 
new pipelines under this rule will also realize a benefit, since in the 
absence of this rule (or a special permit addressing the same issues) 
they would either have to carry less gas or incur additional costs. 
PHMSA has revised the discussion in the regulatory analysis to help 
make this point more clearly.

D. Consideration by the Technical Pipeline Safety Standards Committee 
(TPSSC)

    The TPSSC met on June 10, 2008, and considered the proposed rule. 
During this discussion, PHMSA provided its preliminary views of changes 
that might be made in response to comments submitted in response to the 
proposed rule.
    PHMSA informed the TPSSC that some changes would be made in rule 
structure, moving some requirements to other sections for better 
applicability (e.g., requirements applicable to existing pipelines 
would be moved from the section of the rule in which construction 
requirements are located).
    PHMSA informed the TPSSC it has not adopted the suggestion by the 
state pipeline safety regulatory agency that submitted comments 
supported by its director (a member of the committee) to place the rule 
in a separate subpart, as that is counter to the general structure of 
part 192.
    TPSSC members expressed concern, as did many commenters, about 
reliance on individual standards or tests. In the final rule, PHMSA has 
allowed use of equivalent methods (e.g., for the macro etch test, 
hardness limits, type of crack arrestors).
    PHMSA informed the TPSSC that the vast majority of commenters 
objected to the proposed requirement for mill hydrostatic inspection 
tests of longer duration and that, as a result, that change would not 
be included in the final rule. PHMSA also noted that most industry 
commenters noted that the proposed rule did not make allowances for 
changes in class location after a pipeline is in service, as do the 
existing regulations.
    The anomaly repair requirements were of concern to industry, who 
asserted the requirements were overly conservative. PHMSA informed the 
TPSSC that this issue is complicated by questions recently raised 
concerning the applicability of remaining strength calculational 
methods to high-stress pipelines and that resolving those questions 
before completing this rule would delay issuance of the rule. PHMSA 
stated that it would conduct a public meeting later this year to 
address the global issue of appropriate calculational methods and 
repair criteria. Changes to this or other regulations requiring 
pipeline repair may be appropriate following that workshop.
    Treatment of existing and pending applications for special permits 
was a significant concern for several members of the TPSSC. PHMSA noted 
that the standards in the final rule are very similar to those applied 
in recent special permits. PHMSA reported its intention to continue to 
review pending special permit applications while this rulemaking 
proceeded. Upon issuance of the final rule, PHMSA expects operators 
desiring to use alternative MAOP to comply with the rule. PHMSA will 
examine special permits that have already been granted, as appropriate, 
to determine if any modifications are needed in light of the outcome of 
this rulemaking.
    Subsequent to discussion, the TPSSC voted unanimously to find the 
proposed rule and supporting regulatory evaluations technically 
feasible, reasonable, practicable, and cost effective, subject to 
incorporation of the changes discussed by PHMSA during this meeting. A 
transcript of the meeting is available in the docket.

E. The Final Rule

    Revisions described in this section are changes to the 
corresponding section in the proposed rule.

E.1. In General

    The rule adds a new section (Sec.  192.620) to Subpart L--
Operations. This new section explains what an operator would have to do 
to operate at a higher MAOP than currently allowed by the design 
requirements. Among the conditions set forth in new Sec.  192.620 is 
the requirement that the pipeline be designed and constructed to more 
rigorous standards. These additional design and construction standards 
are set forth in two additional new sections (Sec. Sec.  192.112 and 
192.328) located in Subpart C--Pipe Design and Subpart G--General 
Construction Requirements for Transmission Lines and Mains, 
respectively. In addition, the rule makes necessary conforming changes 
to existing sections on incorporation by reference (Sec.  192.7), 
change in class location (Sec.  192.611), and maximum allowable 
operating pressure (Sec.  192.619).

E.2. Amendment to Sec.  192.7--Incorporation by Reference

    The rule adds ASTM Designation: A 578/A578M--96 (Re-approved 2001) 
``Standard Specification for Straight-Beam Ultrasonic Examination of 
Plain and Clad Steel Plates for Special Applications'' to the documents 
incorporated by reference under Sec.  192.7. This specification 
prescribes standards for ultrasonic testing of steel plates. It is 
referenced in new Sec.  192.112.

[[Page 62167]]

    The rule also revises the description of item (B)(1) in the table 
of Sec.  192.7(c)(2), API 5L ``Specification for Line Pipe,'' (43rd 
edition and errata), 2004, to indicate that it is referenced in new 
Sec.  192.112 in addition to the locations at which it was referenced 
previously.

E.3. New Sec.  192.112--Additional Design Requirements

    The rule adds a new section to Subpart C--Pipe Design in 49 CFR 
Part 192. The new section, Sec.  192.112, prescribes additional design 
standards required for the steel pipeline to be qualified for operation 
at an alternative MAOP based on higher stress levels. These include 
requirements for rigorous steel chemistry and manufacturing practices 
and standards. Pipelines designed under these standards contain pipe 
with toughness properties to resist damage from outside forces and to 
control fracture initiation and growth. The considerable attention paid 
to the quality of seams, coatings, and fittings will prevent flaws 
leading to pipeline failure. Unlike other design standards, Sec.  
192.112 applies to a new or existing pipeline only to the extent that 
an operator elects to operate at a higher alternative MAOP than allowed 
in current regulations.
    Paragraph (a) sets high manufacturing standards for the steel plate 
or coil used for the pipe. The pipe would be manufactured in accordance 
with Level 2 of API 5L, with the ratio between diameter and wall 
thickness limited to prevent the occurrence of denting and ovality 
during construction or operation. Improved construction and inspection 
practices addressed elsewhere in this rule also help prevent denting 
and ovality.
    Paragraph (a) has been revised in response to comments to add an 
alternative method (and applicable limit) for determining equivalent 
carbon content. In addition, the proposed limit on equivalent carbon 
content of 0.23 (Pcm formula) has been raised to 0.25. Several comments 
suggested deleting the limit on the ratio of pipe D/t, but this limit 
has been retained, as discussed above.
    Paragraph (b) addresses fracture control of the metal. First PHMSA 
expects the metal would be tough; that is, deform plastically before 
fracturing. Second, the pipe would have to pass several tests designed 
to reduce the risk that fractures would initiate. Third, to the extent 
it would be physically impossible for particular pipe to meet toughness 
standards under certain conditions, crack arrestors would have to be 
added to stop a fracture within a specified length.
    Paragraph (b) has been revised to allow alternate means of crack 
arrest. This can include the ``mechanical'' means included in the 
proposed rule but can also include other design features such as use of 
composite sleeves, spacing, increases in wall thickness at appropriate 
distances, etc. This paragraph has also been revised to clarify the 
factors that must be considered by an operator in evaluating resistance 
to fracture initiation and to make clear that this evaluation is 
intended to address the full range of relevant parameters to which the 
pipe will be exposed over its operating lifetime. If unexpected 
situations or a change in operating conditions result in a change in 
these parameters during operation, such that they are outside the 
bounds of those analyzed, operators will be required to review and 
update their evaluation and implement remedial measures to assure 
continued resistance to fracture initiation.
    Paragraph (c) provides tests to verify that there are no 
deleterious imperfections in the plate or coil. The macro etch test 
will identify flaws such as segregation that impact the plate or coil 
quality. Surface and interior flaws such as laminations and cracking 
will show up in UT testing.
    This paragraph has been revised, in response to comments, to change 
``mill inspection program'' to an internal quality management program 
designed to eliminate or detect defects or inclusions that can affect 
pipe quality and to require that such a program be implemented at all 
mills involved in the process of casting the steel, rolling it into 
plate, coil or skelp, and the process of manufacturing the steel into 
line pipe. The revised paragraph also includes an alternative to the 
macro etch test and reference to an additional standard for UT testing 
the plate, coil, skelp or manufactured line pipe. (Equivalent standards 
are also still allowed.)
    In addition to the quality of the steel, the integrity of a pipe 
depends on the integrity of the seams. Paragraph (d) provides for a QA 
program to assure tensile strength and toughness of the seams so that 
they resist breaking under regular operations. Hardness and UT tests 
after mill hydrostatic tests would ensure that the seams did not have 
defects or imperfections that were exposed by the stresses of the 
hydrostatic test pressure.
    Paragraph (e) requires a mill pressure test for new pipe at a 
higher hoop stress than required by current regulations. The mill test 
is used to discover flaws introduced in manufacturing. Because the 
pipeline will be operated at a higher stress level, the more rigorous 
mill test is needed to match (or exceed) the level of safety provided 
for pipelines operated at less than 72 percent of SMYS. Paragraph (e) 
has been revised to eliminate the proposed extension of the duration of 
mill pressure tests.
    Paragraph (f) sets rigorous standards for factory coating designed 
to protect the pipeline from external corrosion. A QA program must 
address all aspects of the application of coating that will protect the 
pipeline. This would include applying a coating resistant to damage 
during transportation and installation of the pipe and examining the 
coated pipeline to determine whether the applied coating is uniform and 
without defects. Thin spots or voids/holidays in the coating make it 
more likely for corrosion to occur and more difficult to protect the 
pipeline cathodically.
    Paragraph (g) requires that factory-made fittings, induction bends, 
and flanges be certified as to their serviceability and quality. In 
addition the CE of these fittings and flanges would need to be 
documented, so that welding procedures could require pre-heat 
temperature to eliminate welding defects.
    Paragraph (g) has been revised to clarify that the serviceability 
certification must address properties such as chemistry, minimum yield 
strength, and minimum wall thickness to meet design conditions. PHMSA 
expects that valves, flanges and fittings should be rated based upon 
the required specification rating class for the alternative MAOP and 
the operator to have documented mill reports with chemistry, minimum 
yield strength, and minimum wall thickness. Where specialty bends such 
as hot bends are used for pipeline segments operating per the 
alternative MAOP, PHMSA expects the operator to address properties such 
as chemistry, minimum yield strength, minimum wall thickness and other 
properties that the hot bending process could alter.
    Paragraph (h) requires compressor design to limit the temperature 
of downstream pipe operating at an alternative MAOP to a specified 
maximum. Higher temperature can damage pipe coating. An exception to 
the specified maximum is allowed if testing of the coating shows it can 
withstand a higher temperature. The testing duration, qualification 
procedures and results must be of sufficient length and rigor to detect 
coating integrity issues for the type coating, operating and 
environmental conditions on the pipeline. Operators

[[Page 62168]]

may also rely on a long-term coating integrity monitoring program to 
justify operation at higher temperatures, provided the program is 
submitted to and reviewed by PHMSA.
    Paragraph (h) has been revised to clarify the allowed exception. 
Testing must address coating adhesion and condition as well as cathodic 
disbondment. Operators are required to submit their test results, 
including the acceptance criteria they applied to assure themselves 
that these characteristics are adequate, to the appropriate PHMSA 
regional office(s) and applicable state regulatory authorities at least 
60 days prior to operating at elevated temperature. (State notification 
applies when the pipeline is located in a state where PHMSA has an 
interstate agent agreement, or an intrastate pipeline is regulated by 
that state.)
    A subtle, but important, change has also been made in the language 
in this paragraph. As proposed, the discharge temperature of compressor 
stations would have been limited to the specified temperature. As 
revised, the temperature of the nearest downstream pipeline segment to 
operate at alternative MAOP must be limited. For situations in which 
the pipeline segment at the discharge of a compressor station operates 
at alternative MAOP, there is no practical difference. The revised 
language, however, allows pipeline operators to implement an 
alternative approach in which they would use pipe operating at 
conventional MAOP from the discharge of a compressor station downstream 
to the point at which pipe temperature will drop to the specified 
limit. This may provide an alternative for situations in which it may 
be difficult to limit the compressor station discharge to the specified 
limit (e.g., southern locations on hot summer days). Gas coolers may be 
installed at compressor stations on pipelines operating per the 
alternative MAOP that need to operate above 120 degrees Fahrenheit. Gas 
cooling at compressor stations is a long standing method for most 
operators to reduce gas pipeline temperatures.

E.4. New Sec.  192.328--Additional Construction Requirements

    The rule also adds a new section to Subpart G--General Construction 
Requirements for Transmission Lines and Mains. The new section, Sec.  
192.328, prescribes additional construction requirements, including 
rigorous QC and inspections, as conditions for operation of the steel 
pipeline at higher stress levels. Unlike other construction standards, 
Sec.  192.328 would apply to a new or existing pipeline only to the 
extent that an operator elects to operate at a higher alternative MAOP 
than allowed in current regulations.
    Paragraph (a) requires a QA plan for construction. QA, also called 
QC, is common in modern pipeline construction. Activities such as 
lowering the pipe into the ditch and backfilling, if done poorly, can 
damage the pipe and coating. Other construction activities such as 
nondestructive examination of girth welds, if done poorly, will result 
in flaws remaining in the pipeline or failures during hydrostatic 
testing or while in gas service. Using a QA plan helps to verify that 
the basic tasks done during construction of a pipeline are done 
correctly.
    Field application of coating is one of these basic tasks to be 
covered in a QA plan. During the course of analyzing requests for 
special permits, PHMSA discovered field coatings at one construction 
site which were applied at lower temperature than needed for good 
adhesion to the pipe. Because coating is so critical to corrosion 
protection, paragraph (a) requires quality assurance plans to contain 
specific performance measures for field coating. Field coating must 
meet substantially the same standards as coating applied at the mill 
and the individuals applying the coating must be appropriately trained 
and qualified.
    Installation of the pipe into the ditch and backfilling of the pipe 
are critical operations. PHMSA has found that construction and 
inspection lapses during the backfilling of the pipe have resulted in 
pipe denting and coating damage. Sometimes during backfilling of the 
pipe there are design requirements for the installation of other 
engineered items such as concrete weights at creek and water saturated 
soil areas. The proper installation of these types of engineered items 
is critical to ensure that the pipe and coating are not damaged and the 
item is installed as required in the specifications. PHMSA has found 
operator lapses in this critical QC aspect of pipeline construction.
    Paragraph (b) requires non-destructive testing of all girth welds. 
Although past industry practice sometimes has been to non-destructively 
test only a sample of girth welds, no alternative exists for verifying 
the integrity of the remaining welds. The initial pressure testing once 
construction is complete does not normally detect flaws in girth welds 
unless the girth weld is cracked, has severe lack of penetration or is 
under undue tension stresses, which would be indicative of systemic 
problems on the pipeline. PHMSA believes that most modern pipeline 
construction projects include non-destructive testing of all girth 
welds. However, because the regulations do not require testing of all 
girth welds, an operator's records for pipelines already in operation 
may not be complete on 100 percent of girth welds. To account for this, 
proposed paragraph (b) would have required testing records for only 95 
percent of girth welds on existing segments. This requirement has been 
retained, but proposed paragraph (b) has been moved to new Sec.  
192.620, as it applies to existing pipelines. This section addresses 
pipeline construction.
    Paragraph (c) requires deeper burial of segments operated at higher 
stress level. A greater depth of cover decreases the risk of damage to 
the pipeline from excavation, including farming operations.
    Paragraph (d) addresses the results of the initial strength test 
and the assurance these results provide that the material in the 
pipeline is free of pre-operational flaws which can grow to failure 
over time. Since the initial strength test is a destructive test, it 
only detects flaws that would fail at the test pressure. This could 
leave in place smaller flaws. To prevent this from occurring, the 
proposed paragraph would have disqualified any segment which 
experienced a failure during the initial strength test indicative of 
flaws in the material. Most commenters objected to this provision as 
too restrictive. They noted that failures can be isolated and that it 
was unreasonable to preclude an entire pipeline segment from operation 
at alternative MAOP because of a single failure. This paragraph has 
been revised to allow conduct of a root cause examination of a failure, 
including metallurgic examination of the failed pipe, as a way of 
justifying qualification of the pipeline segment. If that examination 
determines that the cause of the failure is not systemic, then the 
pipeline segment would not be disqualified from alternative MAOP 
operation. Operators must report the results of their root cause 
evaluation to regulators (PHMSA Regional Office or applicable state 
regulatory authorities). Review of these analyses by pipeline safety 
regulators will provide oversight for operator conclusions regarding 
the non-systemic nature of a failure.
    Proposed paragraph (e) addressed cathodic protection on an existing 
segment. This paragraph has been moved to new Sec.  192.620.
    Paragraph (e) (proposed as paragraph (f)) addresses electrical 
interference for new segments. During construction, sources of 
electrical interference which can impair future cathodic protection or

[[Page 62169]]

damage the pipe prior to placing cathodic protection in service need to 
be identified. Addressing interference at this time supports better 
corrosion control. Operators will need to coordinate with electric 
transmission line operators prior to pipeline construction to identify 
locations of grounding structures and power line currents and voltages 
and their effect on the pipe. The additional O&M requirements of new 
Sec.  192.620(d)(6) require operators electing to operate existing 
pipelines at higher stress levels to address electrical interference 
prior to raising the MAOP.

E.5. Amendment to Sec.  192.611--Change in Class Location: Confirmation 
or Revision of Maximum Allowable Operating Pressure

    The proposed rule did not include a provision to amend this 
section. Commenters pointed out that this section addresses changes in 
class location (e.g., increase in population density near the pipeline) 
during operation. The existing requirements allow continued operation 
at pressures higher than would be required for new pipe installed in 
the new class location, provided pressure testing has been performed at 
appropriate pressures. The commenters noted that without addressing 
operation at alternative MAOP in this section, the regulations would 
effectively rescind the authorization provided by this rule to operate 
at higher pressure whenever there was a change in class location.
    PHMSA agrees that this result was not intended. This section has 
been revised to include provisions for pipelines operating at 
alternative MAOP substantially the same as those already provided for 
existing pipelines. Operation at higher alternative pressures can 
continue after a class location change, again provided that the 
pipeline has been tested at appropriate pressures and is not an 
alternative MAOP operating in a Class 3 location that is upgraded to a 
Class 4 location. The limits on hoop stress included in this section 
have been revised to reflect the higher hoop stress that will be 
experienced by a pipeline at alternative MAOP.

E.6. Amendment to Sec.  192.619--Maximum Allowable Operating Pressure

    The final rule amends existing Sec.  192.619 by adding a new 
paragraph (d) providing an additional means to determine the 
alternative MAOP for certain steel pipelines. In addition, the rule 
makes conforming changes to existing paragraph (a) of the section.

E.7. New Sec.  192.620--Operation at an Alternative MAOP

    The final rule adds a new section, Sec.  192.620, to subpart L of 
part 192, to specify what actions an operator must take in order to 
elect an alternative MAOP based on higher operating stress levels. The 
rule applies to both new and existing pipelines.

E.7.1. Sec.  192.620(a)--Calculating the Alternative MAOP

    Paragraph (a) describes how to calculate the alternative MAOP based 
on the higher operating stress levels. Qualifying segments of pipeline 
would use higher design factors to calculate the alternative MAOP. For 
a segment currently in operation this would result in an increase in 
MAOP. No changes were proposed in the design factors used for segments 
within compressor or meter stations or segments underlying certain 
crossings. PHMSA expects new pipelines operating per the alternative 
MAOP to have road/railroad crossings, fabrications, headers, mainline 
valve assemblies, separators, meter stations and compressor stations 
designed and operated per existing design factors in Sec.  192.111.
    Paragraph (a) has been revised to include new design factors for 
compressor/meter stations or segments underlying certain crossings. 
These factors apply to facilities in existence prior to the effective 
date of this rule. Commenters pointed out that compressor stations for 
existing pipelines have been designed and that failure to allow 
alternative design factors for them could effectively preclude 
operation at alternative MAOP for the existing pipelines of which they 
are a part. PHMSA agrees this was not our intent. The additional risk 
associated with use of slightly higher design factors for these 
facilities is marginal. At the same time, there is little additional 
cost associated with designing stations/crossings/fabrications/headers 
for future pipelines to serve at the desired MAOP using existing design 
factors in Sec.  192.111(b), (c), and (d). The rule includes no 
alternative design factors for these facilities in future pipelines, 
and operators must use the existing requirements.

E.7.2. Sec.  192.620(b)--Which Pipeline Qualifies

    Paragraph (b) describes which segments of new or existing pipeline 
are qualified for operation at the alternative MAOP. The alternative 
MAOP is allowed only in Class 1, 2, and 3 locations. Only steel 
pipelines meeting the rigorous design and construction requirements of 
Sec. Sec.  192.112 and 192.328 and monitored by supervisory data 
control and acquisition systems qualify. Mechanical couplings in lieu 
of welding are not allowed. Although the special permits did not 
expressly mention mechanical couplings, PHMSA would not have granted a 
special permit if the pipeline involved had mechanical couplings.
    As proposed, paragraph (b) would have excluded from consideration 
any existing pipeline that had experienced a failure indicative of 
materials concerns. This provision has been revised to allow root cause 
analysis to determine if the failure is indicative of a systemic 
problem and to preclude use of an alternative MAOP only if a failure is 
determined to be systematic in nature. Results of the analysis must be 
reported to regulators (PHMSA Regional Office or applicable state 
regulatory authorities). This is essentially the same change made for 
new pipelines in new Sec.  192.328(d), as described above. Paragraph 
(b) has also been revised to include the requirement that 95 percent of 
girth welds must have been examined for existing pipelines to operate 
at alternative MAOP. This requirement was moved from proposed Sec.  
192.328(e), as discussed above.

E.7.3. Sec. Sec.  192.620(c)(1), (2), and (3)--How an Operator Selects 
Operation Under This Section

    Paragraph (c)(1) requires an operator to notify PHMSA, and 
applicable state pipeline safety regulators, when it elects to 
establish an alternative MAOP under this section. This notification 
must be provided at least 180 days prior to commencing operations at 
the alternative MAOP established under this section. This will provide 
PHMSA and states sufficient time for appropriate inspection which may 
include checks of the manufacturing process, visits to the pipeline 
construction sites, analysis of operating history of existing 
pipelines, and review of test records, plans, and procedures.
    Paragraph (c)(3) requires an operator to further notify PHMSA when 
it has completed the actions necessary to support operation at an 
alternative MAOP, by submitting a certification by a senior executive 
that the pipeline meets the requirements for operation at alternative 
MAOP. The certification is required by paragraph (c)(2). A senior 
executive must certify that the pipeline meets the additional design 
and construction regulations of this rule. A senior executive must also 
certify that the operator has changed its O&M procedures to include the 
more rigorous

[[Page 62170]]

additional O&M requirements. In addition, a senior executive must 
certify that the operator has reviewed its damage prevention program in 
light of best practices, such as CGA best practices or some equivalent 
best practices, and made any needed changes to it to ensure that the 
program meets or exceeds those standards or practices. The 
certification must be submitted at least 30 days prior to operation at 
an alternative MAOP.

E.7.4. Sec.  192.620(c)(4)--Initial Strength Testing

    Paragraph (c)(4) addresses initial strength testing requirements. 
In order to establish the MAOP under this section, an operator must 
perform the initial strength testing of a new segment at a pressure at 
least as great as 125 percent of the MAOP in Class 1 locations and 150 
percent in Class 2 and 3 locations. Since an existing pipeline was 
previously operated at a lower MAOP, it may have been initially tested 
at a pressure less than these levels. If so, paragraph (c) allows the 
operator to elect to conduct a new strength test in order to raise the 
MAOP.

E.7.5. Sec.  192.620(c)(5)--Operation and Maintenance

    Paragraph (c)(5) requires an operator to comply with the additional 
operating and maintenance requirements of Sec.  192.620(d). An operator 
must comply with these additional requirements if the operator elects 
to calculate the alternative MAOP for a segment under Sec.  192.620(a) 
and notifies PHMSA of that election.

E.7.6. Sec.  192.620(c)(6)--New Construction and Maintenance Tasks

    Paragraph (c)(6) addresses the need for competent performance of 
both new construction, and future maintenance activities, to ensure the 
integrity of the segment. PHMSA now requires operators to ensure that 
individuals who perform pipeline O&M activities are qualified. 
Paragraph (c)(6) requires operators seeking to operate at the allowable 
higher operating stress levels to treat construction tasks as if they 
were covered by subpart N, ``Qualification of Pipeline Personnel.'' 
Subpart N (commonly known as OQ) specifies training and qualification 
requirements applicable to tasks that meet a four-part test in Sec.  
192.801(b). Operations and maintenance tasks on the pipeline meet this 
test, and it is the requirements in subpart N that will govern training 
and qualification of personnel performing these tasks on a pipeline to 
be operated at an alternative MAOP. Construction tasks typically do not 
meet the four-part test and are not covered under subpart N. As 
proposed, paragraph (c)(6) (then designated (c)(5)) would have required 
operators to take other actions to assure qualification of personnel 
performing construction tasks on a pipeline intended to operate at 
alternative MAOP. Commenters noted that the proposed requirements were 
vague and subject to interpretation and suggested that PHMSA, instead, 
rely on the known requirements of subpart N. This paragraph has been 
modified, in response to these comments, to require that the 
requirements of subpart N be applied to construction tasks for a 
pipeline intended to operate at alternative MAOP regardless of the 
four-part test in Sec.  192.801(b).

E.7.7. Sec.  192.620(c)(7)--Recordkeeping

    Paragraph (c)(7) specifies recordkeeping requirements for operators 
electing to establish the MAOP under this section. Existing 
regulations, such as Sec. Sec.  192.13, 192.517(a), and 192.709, 
already require operators to maintain records applicable to this 
section. New Sec.  192.620 is in subpart L. Because the additional 
requirements in this section address requirements found in other 
subparts of part 192, the recordkeeping requirements could cause 
confusion. For example, Sec.  192.620(d)(9) requires a baseline 
assessment for integrity for a segment operated at the higher stress 
level regardless of its potential impact on an HCA. Section 192.947, in 
subpart O, requires operators to maintain records of baseline 
assessments for the useful life of the pipeline. Section 192.709 
requires an operator to retain records for an inspection done under 
subpart L for a more limited time. Accordingly, this paragraph 
clarifies the need to maintain all records demonstrating compliance 
with all alternative MAOP requirements for the useful life of the 
pipeline.

E.7.8 Sec.  192.620(c)(8)--Class Upgrades

    Paragraph (c)(8) allows pipelines in Class 1 and 2 to be upgraded 
one class when class changes occur per Sec.  192.611. This paragraph 
precludes operation of pipeline in Class 4 at alternative MAOP.

E.8. Sec.  192.620(d)--Additional Operation and Maintenance 
Requirements

    Paragraph (d) sets forth ten operating and maintenance requirements 
that supplement the existing requirements in part 192. Currently Sec.  
192.605 requires an operator to develop O&M procedures to implement the 
requirements of subparts L and M. Since Sec.  192.620(d) is in subpart 
L, an operator must develop and follow the O&M procedures developed 
under this section. These include requirements for an operator to 
evaluate and address the issues associated with operating at higher 
pressures. Through its public education program, an operator would 
inform the public of any risks attributable to higher pressure 
operations. The additional operating and maintenance requirements 
address the two main risks the pipelines face, excavation damage and 
corrosion, through a combination of traditional practices and integrity 
management. Traditional practices include cathodic protection, control 
of gas quality, and maintenance of burial depth. Integrity management 
includes internal inspection on a periodic basis to identify and repair 
flaws before they can fail. The additional O&M and management 
requirements are discussed in more detail below.

E.8.1. Sec.  192.620(d)(1)--Threat Assessments

    Paragraph (d)(1) requires an operator to identify and evaluate 
threats to the pipeline consistent with the similar procedures done 
under integrity management to address the risks of operating at an 
increased stress level.

E.8.2. Sec.  192.620(d)(2)--Public Awareness

    Paragraph (d)(2) requires an operator to include any people 
potentially impacted by operation at a higher stress level within the 
outreach effort in its public education program required under existing 
Sec.  192.616. In order to identify this population, an operator would 
use a broad area measured from the centerline of the pipe plus, in 
HCAs, the potential impact circle recalculated to reflect operation at 
a higher operating stress level. This is intended to get necessary 
information for safety to the people potentially impacted by a failure.

E.8.3. Sec.  192.620(d)(3)--Emergency Response

    Paragraph (d)(3) addresses the additional needs for responding to 
emergencies for operation at higher operating stress levels. Consistent 
with the conditions imposed in the special permits, and past experience 
with response issues, the paragraph requires methods such as remote 
control valves to provide more rapid shut-down in the event of an 
emergency.

E.8.4. Sec.  192.620(d)(4)--Damage Prevention

    Paragraph (d)(4) addresses one of the major risks of failure faced 
by a pipeline, damage from outside force such as damage occurring 
during excavation in the right-of-way. Although

[[Page 62171]]

the improved toughness of pipe reduces the risk of damage, it does not 
prevent it and additional measures are appropriate for pipelines 
operating at higher operating stress levels. This paragraph adds 
several new or more specific measures to existing requirements designed 
to prevent damage to pipelines from outside force.
    The first more specific measure, in paragraph (d)(4)(i), addresses 
patrolling, required for all transmission pipelines by Sec.  192.705. 
More frequent patrols of the right-of-way prevent damage by giving the 
operator more accurate and timely information about potential sources 
of ground disturbance and other outside force damage. These include 
both naturally occurring conditions, such as wash outs, and human 
activity, such as construction in the vicinity of the pipeline. The 
requirement is for patrols to be made monthly, at intervals not to 
exceed 45 days. The patrolling requirement along with other right-of-
way requirements including line-of-sight markers, use of national 
consensus standards, and the right-of-way management plan comprise a 
multi-faceted approach to protecting the pipeline.
    Other more specific or new measures to address damage prevention 
include developing and implementing a plan to monitor and address 
ground movement, a requirement of paragraph (d)(4)(ii). Ground movement 
such as earthquakes, landslides, soil erosion, and nearby demolition or 
tunneling can damage pipelines. Since pipelines near the surface are 
more likely to be damaged by surface activities, paragraph (d)(4)(iii) 
requires an operator to maintain the depth of cover over a pipeline or 
provide alternative protection. Line-of-sight markers alert excavators, 
emergency responders, and the general public of the presence and 
general location of pipelines. Paragraph (d)(4)(iv) requires these 
markers both to improve damage prevention and to enhance public 
awareness.
    Damage prevention programs are improving because of the work being 
done by the CGA, a national, non-profit educational organization 
dedicated to preventing damage to pipelines and other underground 
utilities. The CGA has compiled best practices applicable to all 
parties relevant to preventing damage to underground utilities and 
actively promotes their use. Paragraph (d)(5)(v) requires operators 
electing to operate at higher stress levels to evaluate their damage 
prevention programs in light of industry best practices, such as those 
developed by CGA. An operator must identify the practices applicable to 
its circumstances and make appropriate changes to its damage prevention 
program. This approach is consistent with annual reviews of O&M 
programs under Sec.  192.605. An operator must include in the 
certification required under Sec.  192.620(c)(1) that the review and 
upgrade have occurred.
    Paragraph (d)(4) also requires the preparation of a right-of-way 
management plan. In the past several years, PHMSA has seen recurring 
similarities in pipeline accidents on construction sites. In each case, 
better management of the pipeline right-of-way could have prevented the 
accidents. Better management includes closer attention to the 
qualifications of individuals critical to damage prevention, better 
marking practices, and closer oversight of the excavation. In 2006, 
PHMSA issued two advisory bulletins to alert operators of the need to 
pay closer attention to these important damage prevention issues. The 
first advisory bulletin described three accidents in which either 
operator personnel or contractors damaged gas transmission pipelines 
during excavation in the rights-of-way (ADB-06-01; 71 FR 2613; Jan.17, 
2006). This bulletin advised operators to pay closer attention to 
integrating OQ regulations into excavation activities and providing 
that excavation is included as a covered task under OQ programs 
required by subpart N. The second advisory bulletin pointed to an 
additional excavation accident where the excavator struck an 
inadequately marked gas transmission pipeline (ADB-06-003; 71 FR 67703; 
Nov. 22, 2006). This advisory bulletin advised pipeline operators to 
pay closer attention to locating and marking pipelines before 
excavation activities begin and pointed to several good practices as 
well as the best practices described by the CGA. This paragraph 
requires an operator electing to operate at a higher stress level to 
develop a plan to manage the protection of their right-of-way from 
excavation activities. Each operator already has a damage prevention 
program, under Sec.  192.614, and a program to ensure qualification of 
pipeline personnel, under subpart N. This management program requires 
the operator to integrate activities under those programs to provide 
better protection for the right-of-way of the pipeline operated at the 
higher stress level.

E.8.5. Sec.  192.620(d)(5)--Internal Corrosion Control

    Paragraph (d)(5) adds specificity to the requirements for internal 
corrosion control now in pipeline safety standards for pipelines 
operated at higher stress levels. These internal corrosion control 
programs must include use of gas separators or filter separators and 
gas quality monitoring equipment. Operators are required to use 
cleaning pigs and inhibitors when corrosive gas is present. (Use of 
cleaning pigs and inhibitors is required when the level of one 
corrosive contaminant, hydrogen sulfide (H<INF>2</INF>S), is between 
0.5 and 1.0 grain per hundred cubic feet). Most operators who have 
applied for special permits to operate their pipeline at alternative 
MAOP limit H<INF>2</INF>S to 0.5 grain. The higher levels allowed in 
this rule are within typical FERC tariffs, but may present an increased 
likelihood of internal corrosion. Maximum levels of contaminants that 
could promote corrosion must be reviewed quarterly, and operators must 
adjust their programs as needed to monitor and mitigate any deleterious 
gas stream constituents. PHMSA believes the levels are fully consistent 
with the requirements in FERC tariffs designed to prevent internal 
corrosion.

E.8.6. Sec. Sec.  192.620(d)(6), (7), and (8)--External Corrosion 
Control

    Since external corrosion is one of the greatest risks to the 
integrity of pipelines operating at higher stress levels, the special 
permits and this rule contain several measures to prevent it from 
occurring. These include use of effective external coating, addressing 
interference, early installation of cathodic protection, confirming the 
adequacy of coating and cathodic protection and diligent monitoring of 
cathodic protection levels. The requirements concerning quality of the 
coating and installation of cathodic protection for new pipelines are 
addressed in sections on design and construction, as discussed above. 
The remaining external corrosion provisions are addressed here.
    Interference from overhead power lines, railroad signaling, stray 
currents, or other sources can interfere with the cathodic protection 
system and, if not properly mitigated, even accelerate the rate of 
external corrosion. Paragraph (d)(6) requires an operator to identify 
and address interference early before damage to the pipeline can occur.
    Paragraph (d)(7) requires an operator to confirm both the 
effectiveness of the coating and the adequacy of the cathodic 
protection system soon after deciding on operation at higher operating 
stress levels/alternative MAOP. This is accomplished through indirect 
assessments, such as a CIS for cathodic protection and DCVG or ACVG for 
coating condition. After completion of the baseline internal inspection

[[Page 62172]]

required by Sec.  192.620(d)(9), an operator is required to integrate 
the results of that inspection with the indirect assessments. An 
operator must take remedial action to correct any inadequacies. In 
HCAs, an operator must periodically repeat indirect assessment to 
confirm that the cathodic protection system remains as functional as 
when first installed.
    Paragraph (d)(8) requires more rigorous attention to ensure 
adequate levels of cathodic protection. Regulations now require an 
operator discovering a low reading, meaning a reduced level of 
protection, to act promptly to correct the deficiency. This section 
puts an outer limit of six months on the time for completion of the 
remedial action and restoration of an adequate level of cathodic 
protection. In addition, the operator must confirm that its actions 
have been effective in restoring cathodic protection.

E.8.7. Sec. Sec.  192.620(d)(9) and (10)--Integrity Assessments

    Among the most important ways of ensuring integrity during pipeline 
operations are the assessments done under the integrity management 
program requirements in subpart O. Paragraphs (d)(9) and (d)(10) 
require operators electing to operate at higher stress levels to 
perform both baseline and periodic assessments of the entire pipeline 
segment operating at the higher stress level, regardless of whether the 
pipeline segment is located in an HCA. The operator must use both a 
geometry tool and a high resolution magnetic flux tool for the entire 
pipeline segment. In very limited circumstances in which internal 
inspection is not possible because internal inspection tools cannot be 
accommodated, such as a short crossover segment connecting two 
pipelines in a right-of-way, an operator would substitute pressure 
testing or DA. The operator must then integrate the information 
provided by these assessments with testing done under previously 
described paragraphs. This analysis would form the basis for mitigating 
measures, and for prompt repairs under paragraph (d)(11).

E.8.8. Sec.  192.620(d)(11)--Repair Criteria

    The repair criteria under paragraph (d)(11) for anomalies in a 
pipeline segment operating at a higher stress level are slightly more 
conservative than for other pipelines, including pipelines covered by 
an integrity management program. With the tougher pipe, better coating, 
construction quality inspection program, coating surveys after 
installation and backfill, and careful attention to damage prevention 
and corrosion protection, a pipeline operated at higher operating 
stress levels should experience few anomalies needing evaluation.

E.9. Sec.  192.620(e)--Overpressure Protection

    The alternative MAOP is higher than the upper limit of the required 
overpressure protection under existing regulations. Paragraph (e) 
increases the overpressure protection limit to 104 percent of the MAOP, 
which is 83.2 percent of SMYS for a pipeline segment operating at the 
alternative MAOP in a Class 1 location.

F. Regulatory Analyses and Notices

F.1. Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act Statement 
in the Federal Register published on April 11, 2000 (65 FR 19477).

F.2. Executive Order 12866 and DOT Policies and Procedures

    Due to magnitude of expected benefits, the DOT considers this 
rulemaking to be a significant regulatory action under section 3(f)(1) 
of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). Therefore, DOT 
submitted it to the Office of Management and Budget for review. This 
rulemaking is also significant under DOT regulatory policies and 
procedures (44 FR 11034; Feb. 26, 1979).
    PHMSA prepared a Regulatory Evaluation of the final rule. A copy is 
in Docket ID PHMSA-2005-23447.
    PHMSA estimates that the rule will result in gas transmission 
pipeline operators uprating 3,500 miles of existing pipelines to an 
alternative MAOP. Additionally PHMSA estimates that, in the future, the 
rule will result in an annual additional 700 miles of new pipelines 
each year whose operators elect to use an alternative MAOP.
    PHMSA expects the benefits of the rule to be substantial and in 
excess of $100 million per year. This expectation is based on 
quantified benefits in excess of $100 million per year (see below), 
coupled with un-quantified benefits associated with the rule that 
industry and PHMSA technical staff have identified. The expected 
benefits of the rule that cannot be readily quantified include:
    <bullet> Reductions in incident consequences.
    <bullet> Increases in pipeline capacity.
    <bullet> Increases in the amount of natural gas filling the line, 
commonly called line pack.
    <bullet> Reductions in adverse environmental impacts.
    The rule's requirements, such as monthly right-of-way patrolling, 
additional internal inspections, and anomaly repair, are expected to 
prevent incidents that would have occurred in the absence of the rule, 
and to help mitigate the consequences of the incidents that do occur. 
In the case of new pipelines, the ability to use an alternative MAOP 
will make it possible to transport more product per dollar of pipeline 
cost than would be possible without this new rule. Quantifying the 
value of this increased capacity is difficult, and no estimate has been 
developed for this analysis. For existing pipelines, operation at a 
higher MAOP increases the amount of gas that can be transported. PHMSA 
expects the value of increased capacity due to use of alternative MAOP 
by gas pipelines to be significant. In areas where production is 
already well-established, there is an even greater potential for 
increased pipeline capacity. For example, one recipient of a special 
permit estimated a daily increase of at least 62 million standard cubic 
feet of gas.
    Similarly, increases in line pack will produce increased benefits 
which are difficult to quantify. Line pack is increased due to gas 
compressibility at higher operating pressures which results in 
increased gas volumes in the pipeline. The reduced amount of exterior 
storage capacity needed resulting from increased line pack may result 
in capital or O&M savings for the pipelines or their customers. Greater 
line pack in a pipeline increases the ability of the operator to 
continue gas delivery during short outages such as maintenance and 
during peak flow periods. These benefits are not readily quantifiable.
    The quantified benefits consist of:
    <bullet> Fuel cost savings.
    <bullet> Capital expenditure savings on pipe for new pipelines.
    Of these, pipeline fuel cost savings is the most important 
contributor to the estimated benefits. Although these quantified 
benefits do not capture the full benefits of the rule, they exceed $100 
million per year.
    As a consequence of the rule, PHMSA estimates that pipeline 
operators will realize annually recurring benefits due to fuel cost 
savings of $49 million that will begin in the initial year after the 
rule goes into effect. Additionally, PHMSA estimates that each year 
pipeline operators will realize one-time benefits for savings in 
capital expenditures of $54.6 million (since 700 miles of new pipeline 
operating at an alternative MAOP are added each year,

[[Page 62173]]

the one-time benefits resulting from this added mileage will be the 
same each year.) The benefits of the rule over 20 years are expected to 
be as presented in the following table:

 Table D.2.-1--Summary and Total for the Estimated Benefits of the Rule
                      [Millons of dollars per year]
------------------------------------------------------------------------
                                                        Estimate of new
                                   Estimate for year  benefits occurring
             Benefit                       1          in each subsequent
                                                             year
------------------------------------------------------------------------
Reduced incident consequences...  Not quantified....  Not quantified.
Fuel cost savings...............  $49.0.............  $49.0
Reduced capital expenditures....  $54.6.............  $54.6
Increased pipeline capacity.....  Not quantified....  Not quantified.
Increased line pack.............  Not quantified....  Not quantified.
Reduced adverse environmental     Not quantified....  Not quantified.
 impacts.
Other expected benefits.........  Not quantified....  Not quantified.
                                 ---------------------------------------
    Total.......................  $103.6............  $103.6
------------------------------------------------------------------------

    The present value of the benefits evaluated over 20 years at a 
three percent discount rate is $1,541 million, while the present value 
of the benefits over 20 years at a seven percent discount rate is 
$1,098 million. For both discount rates, the annualized benefits would 
be $103.6 million.
    PHMSA expects the costs attributable to the rule are most likely to 
be incurred by operators for:
    <bullet> Performing baseline internal inspections.
    <bullet> Performing additional internal inspections.
    <bullet> Performing anomaly repairs.
    <bullet> Installing remotely controlled valves on either side of 
HCAs.
    <bullet> Preparing threat assessments.
    <bullet> Patrolling pipeline rights-of-way.
    <bullet> Preparing the paperwork notifying PHMSA of the decision to 
use an alternative MAOP.
    Overall, the costs of the rule over 20 years are expected to be as 
presented in the following table:

                      Table D.2.-2-- Summary and Totals for the Estimated Costs of the Rule
----------------------------------------------------------------------------------------------------------------
                                             Cost by year after implementation  [thousands of dollars]
            Cost item            -------------------------------------------------------------------------------
                                          1st              2nd--10th             11th             12th--20th
----------------------------------------------------------------------------------------------------------------
Baseline internal inspections...  $29,119...........  None..............  None..............  None
Additional internal inspections.  None..............  None..............  $17,471...........  $2,912 each year.
Anomaly repairs.................  $1,015............  None..............  $1,218............  $203 each year.
Remotely controlled valves......  $3,528............  $588 each year....  $588..............  $588 each year.
Threat Assessments..............  $180..............  $30 each year.....  $30...............  $30 each year.
Patrolling......................  $4,620............  $5,390 to $11,550.  $12,320...........  $15,090 to
                                                                                               $19,250.
Notifying PHMSA.................  Nominal...........  Nominal...........  Nominal...........  Nominal.
                                 -------------------------------------------------------------------------------
    Total.......................  $38,462...........  $618 each year      $31,627...........  $3,733 each year
                                                       plus patrolling                         plus patrolling
                                                       costs.                                  costs.
----------------------------------------------------------------------------------------------------------------

    The present value of the costs evaluated over 20 years at a three 
percent discount rate are approximately $239 million, while the present 
value of the costs over 20 years at a seven percent discount rate are 
approximately $165 million. The annualized costs at the three percent 
discount rate are approximately $16 million, while the annualized costs 
at the seven percent discount rate are approximately $15 million.
    Since the present value of the quantified benefits ($1,541 million 
at three percent and $1,098 million at seven percent) exceeds the 
present value of the costs ($328 million at three percent and $164 
million at seven percent), the rule is expected to have net benefits.

F.3. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether rulemaking actions would have a significant 
economic impact on a substantial number of small entities.
    The final rule affects operators of gas pipelines. Based on annual 
reports submitted by operators, there are approximately 1,450 gas 
transmission and gathering systems and an equivalent number of 
distribution systems potentially affected by this rule. The size 
distribution of these operators is unknown and must be estimated.
    The affected gas transmission systems all belong to NAICS 486210, 
Pipeline Transportation of Natural Gas. In accordance with the size 
standards published by the Small Business Administration, a business 
with $6.5 million or less in annual revenue is considered a small 
business in this NAICS.
    Based on August 2006 information from Dunn & Bradstreet on firms in 
NAICS 486210, PHMSA estimates that 33 percent of the gas transmission 
and gathering systems have $6.5 million or less in revenue. Thus, PHMSA 
estimates that 479 of the gas transmission and gathering systems 
affected by the rule will have $6.5 million or less in annual revenue. 
PHMSA does not expect that

[[Page 62174]]

any local gas distribution companies or gathering systems will be 
taking advantage of the potential to use an alternative MAOP.
    The rule mandates no action by gas transmission pipeline operators. 
Rather, it provides those operators with the option of using an 
alternative MAOP in certain circumstances, when certain conditions can 
be met. Consequently, it imposes no economic burden on the affected gas 
pipeline operators, large or small. Based on these facts, I certify 
that this rule will not have a substantial economic impact on a 
substantial number of small entities.

F.4. Executive Order 13175

    PHMSA has analyzed this rulemaking according to Executive Order 
13175, ``Consultation and Coordination with Indian Tribal 
Governments.'' Because the rule does not significantly or uniquely 
affect the communities of the Indian tribal governments, nor impose 
substantial direct compliance costs, the funding and consultation 
requirements of Executive Order 13175 do not apply.

F.5. Paperwork Reduction Act

    This rule adds notification paperwork requirements and record 
retention on pipeline operators voluntarily choosing an alternative 
MAOP for their pipelines. Based on analysis of the regulation, there 
will be an estimated nine total annual burden hours attributable to the 
notification and recordkeeping requirements in the first year. In 
following years, the annual burden is expected to decrease to one and 
one-half hours. The associated cost of these annual burden hours is 
$720 in year one, and $120 thereafter. No other burden hours and 
associated costs are expected. The Paperwork Reduction Act analysis in 
the docket has a more detailed explanation.

F.6. Unfunded Mandates Reform Act of 1995

    This rule does not impose unfunded mandates under the Unfunded 
Mandates Reform Act of 1995. It does not result in costs of $132 
million or more in any one year to either State, local, or tribal 
governments, in the aggregate, or to the private sector, and is the 
least burdensome alternative that achieves the objective of the 
rulemaking.

F.7. National Environmental Policy Act

    PHMSA has analyzed the rulemaking for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.). The rulemaking will 
require limited physical change or other work that would disturb 
pipeline rights-of-way. In addition, the rule codifies the terms of 
special permits PHMSA has granted. Although PHMSA sought public comment 
on environmental impacts with respect to most requests for special 
permits to allow operation at pressures based on higher stress levels, 
no commenters addressed environmental impacts. Further, PHMSA did not 
receive any comment on the environmental assessment it had prepared in 
conjunction with the proposed rule. PHMSA has determined the rulemaking 
is unlikely to significantly affect the quality of the human 
environment. An environmental assessment document is available for 
review in the docket.

F.8. Executive Order 13132

    PHMSA has analyzed the rulemaking according to Executive Order 
13132 (64 FR 43255, Aug. 10, 1999) and concluded that no additional 
consultation with States, local governments or their representatives is 
mandated beyond the rulemaking process. The rule does not have a 
substantial direct effect on the States, the relationship between the 
national government and the States, or the distribution of power and 
responsibilities among the various levels of government. The rule does 
not impose substantial direct compliance costs on State or local 
governments.
    Further, no consultation is needed to discuss the preemptive effect 
of the proposed rule. The pipeline safety law, specifically 49 U.S.C. 
60104(c), prohibits State safety regulation of interstate pipelines. 
Under the pipeline safety law, States have the ability to augment 
pipeline safety requirements for intrastate pipelines PHMSA regulates, 
but may not approve safety requirements less stringent than those 
required by Federal law. And a State may regulate an intrastate 
pipeline facility PHMSA does not regulate. In addition, 49 U.S.C. 
60120(c) provides that the Federal pipeline safety law ``does not 
affect the tort liability of any person.'' It is these statutory 
provisions, not the rule, that govern preemption of State law. 
Therefore, the consultation and funding requirements of Executive Order 
13132 do not apply.

F.9. Executive Order 13211

    This rulemaking is likely to increase the efficiency of gas 
transmission pipelines. A gas transmission pipeline operating at an 
increased MAOP will result in increased capacity, fuel savings, and 
flexibility in addressing supply demands. This is a positive rather 
than an adverse effect on the supply, distribution, and use of energy. 
Thus this rulemaking is not a ``significant energy action'' under 
Executive Order 13211. Further, the Administrator of the Office of 
Information and Regulatory Affairs has not identified this rule as a 
significant energy action.

List of Subjects in 49 CFR Part 192

    Design pressure, Incorporation by reference, Maximum allowable 
operating pressure, and Pipeline safety.

0
For the reasons provided in the preamble, PHMSA amends 49 CFR part 192 
as follows:

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

0
1. The authority citation for part 192 continues to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, and 60118; and 49 CFR 1.53.

0
2. In Sec.  192.7, in paragraph (c)(2) amend the table of referenced 
material by revising item (B)(1), redesignating items (C)(6) through 
(C)(13) as (C)(7) through (C)(14), and adding a new item (C)(6) to read 
as follows:


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

* * * * *
    (c) * * *
    (2) * * *

[[Page 62175]]



------------------------------------------------------------------------
   Source and name of referenced material          49 CFR reference
------------------------------------------------------------------------
B. * * *...................................  * * *
(1) API Specification 5L ``Specification     Sec.  Sec.   192.55(e);
 for Line Pipe,'' (43rd edition and           192.112; 192.113; Item I
 errata), 2004.                               of Appendix B.
                              * * * * * * *
C. * * *...................................  ...........................
(6) ASTM Designation: A 578/A578M-96 (Re-    Sec.  Sec.
 approved 2001) ``Standard Specification      192.112(c)(2)(iii).
 for Straight-Beam Ultrasonic Examination
 of Plain and Clad Steel Plates for Special
 Applications''.
                              * * * * * * *
------------------------------------------------------------------------


0
3. Add Sec.  192.112 to subpart C to read as follows:


Sec.  192.112  Additional design requirements for steel pipe using 
alternative maximum allowable operating pressure.

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure (MAOP) 
calculated under Sec.  192.620, a segment must meet the following 
additional design requirements. Records for alternative MAOP must be 
maintained, for the useful life of the pipeline, demonstrating 
compliance with these requirements:

------------------------------------------------------------------------
                                    The pipeline segment must meet these
   To address this design issue:          additional requirements:
------------------------------------------------------------------------
(a) General standards for the       (1) The plate, skelp, or coil used
 steel pipe.                         for the pipe must be micro-alloyed,
                                     fine grain, fully killed,
                                     continuously cast steel with
                                     calcium treatment.
                                    (2) The carbon equivalents of the
                                     steel used for pipe must not exceed
                                     0.25 percent by weight, as
                                     calculated by the Ito-Bessyo
                                     formula (Pcm formula) or 0.43
                                     percent by weight, as calculated by
                                     the International Institute of
                                     Welding (IIW) formula.
                                    (3) The ratio of the specified
                                     outside diameter of the pipe to the
                                     specified wall thickness must be
                                     less than 100. The wall thickness
                                     or other mitigative measures must
                                     prevent denting and ovality
                                     anomalies during construction,
                                     strength testing and anticipated
                                     operational stresses.
                                    (4) The pipe must be manufactured
                                     using API Specification 5L, product
                                     specification level 2 (incorporated
                                     by reference, see Sec.   192.7) for
                                     maximum operating pressures and
                                     minimum and maximum operating
                                     temperatures and other requirements
                                     under this section.
(b) Fracture control..............  (1) The toughness properties for
                                     pipe must address the potential for
                                     initiation, propagation and arrest
                                     of fractures in accordance with:
                                    (i) API Specification 5L
                                     (incorporated by reference, see
                                     Sec.   192.7); or
                                    (ii) American Society of Mechanical
                                     Engineers (ASME) B31.8
                                     (incorporated by reference, see
                                     Sec.   192.7); and
                                    (iii) Any correction factors needed
                                     to address pipe grades, pressures,
                                     temperatures, or gas compositions
                                     not expressly addressed in API
                                     Specification 5L, product
                                     specification level 2 or ASME B31.8
                                     (incorporated by reference, see
                                     Sec.   192.7).
                                    (2) Fracture control must:
                                    (i) Ensure resistance to fracture
                                     initiation while addressing the
                                     full range of operating
                                     temperatures, pressures, gas
                                     compositions, pipe grade and
                                     operating stress levels, including
                                     maximum pressures and minimum
                                     temperatures for shut-in
                                     conditions, that the pipeline is
                                     expected to experience. If these
                                     parameters change during operation
                                     of the pipeline such that they are
                                     outside the bounds of what was
                                     considered in the design
                                     evaluation, the evaluation must be
                                     reviewed and updated to assure
                                     continued resistance to fracture
                                     initiation over the operating life
                                     of the pipeline;
                                    (ii) Address adjustments to
                                     toughness of pipe for each grade
                                     used and the decompression behavior
                                     of the gas at operating parameters;
                                    (iii) Ensure at least 99 percent
                                     probability of fracture arrest
                                     within eight pipe lengths with a
                                     probability of not less than 90
                                     percent within five pipe lengths;
                                     and
                                    (iv) Include fracture toughness
                                     testing that is equivalent to that
                                     described in supplementary
                                     requirements SR5A, SR5B, and SR6 of
                                     API Specification 5L (incorporated
                                     by reference, see Sec.   192.7) and
                                     ensures ductile fracture and arrest
                                     with the following exceptions:
                                    (A) The results of the Charpy impact
                                     test prescribed in SR5A must
                                     indicate at least 80 percent
                                     minimum shear area for any single
                                     test on each heat of steel; and
                                    (B) The results of the drop weight
                                     test prescribed in SR6 must
                                     indicate 80 percent average shear
                                     area with a minimum single test
                                     result of 60 percent shear area for
                                     any steel test samples. The test
                                     results must ensure a ductile
                                     fracture and arrest.
                                    (3) If it is not physically possible
                                     to achieve the pipeline toughness
                                     properties of paragraphs (b)(1) and
                                     (2) of this section, additional
                                     design features, such as mechanical
                                     or composite crack arrestors and/or
                                     heavier walled pipe of proper
                                     design and spacing, must be used to
                                     ensure fracture arrest as described
                                     in paragraph (b)(2)(iii) of this
                                     section.
(c) Plate/coil quality control....  (1) There must be an internal
                                     quality management program at all
                                     mills involved in producing steel,
                                     plate, coil, skelp, and/or rolling
                                     pipe to be operated at alternative
                                     MAOP. These programs must be
                                     structured to eliminate or detect
                                     defects and inclusions affecting
                                     pipe quality.
                                    (2) A mill inspection program or
                                     internal quality management program
                                     must include (i) and either (ii) or
                                     (iii):
                                    (i) An ultrasonic test of the ends
                                     and at least 35 percent of the
                                     surface of the plate/coil or pipe
                                     to identify imperfections that
                                     impair serviceability such as
                                     laminations, cracks, and
                                     inclusions. At least 95 percent of
                                     the lengths of pipe manufactured
                                     must be tested. For all pipelines
                                     designed after [the effective date
                                     of the final rule], the test must
                                     be done in accordance with ASTM
                                     A578/A578M Level B, or API 5L
                                     Paragraph 7.8.10 (incorporated by
                                     reference, see Sec.   192.7) or
                                     equivalent method, and either

[[Page 62176]]

 
                                    (ii) A macro etch test or other
                                     equivalent method to identify
                                     inclusions that may form centerline
                                     segregation during the continuous
                                     casting process. Use of sulfur
                                     prints is not an equivalent method.
                                     The test must be carried out on the
                                     first or second slab of each
                                     sequence graded with an acceptance
                                     criteria of one or two on the
                                     Mannesmann scale or equivalent; or
                                    (iii) A quality assurance monitoring
                                     program implemented by the operator
                                     that includes audits of: (a) all
                                     steelmaking and casting facilities,
                                     (b) quality control plans and
                                     manufacturing procedure
                                     specifications, (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.
(d) Seam quality control..........  (1) There must be a quality
                                     assurance program for pipe seam
                                     welds to assure tensile strength
                                     provided in API Specification 5L
                                     (incorporated by reference, see
                                     Sec.   192.7) for appropriate
                                     grades.
                                    (2) There must be a hardness test,
                                     using Vickers (Hv10) hardness test
                                     method or equivalent test method,
                                     to assure a maximum hardness of 280
                                     Vickers of the following:
                                    (i) A cross section of the weld seam
                                     of one pipe from each heat plus one
                                     pipe from each welding line per
                                     day; and
                                    (ii) For each sample cross section,
                                     a minimum of 13 readings (three for
                                     each heat affected zone, three in
                                     the weld metal, and two in each
                                     section of pipe base metal).
                                    (3) All of the seams must be
                                     ultrasonically tested after cold
                                     expansion and mill hydrostatic
                                     testing.
(e) Mill hydrostatic test.........  (1) All pipe to be used in a new
                                     pipeline segment must be
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 95 percent SMYS
                                     for 10 seconds. The test pressure
                                     may include a combination of
                                     internal test pressure and the
                                     allowance for end loading stresses
                                     imposed by the pipe mill
                                     hydrostatic testing equipment as
                                     allowed by API Specification 5L,
                                     Appendix K (incorporated by
                                     reference, see Sec.   192.7).
                                    (2) Pipe in operation prior to
                                     November 17, 2008, must have been
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 90 percent SMYS
                                     for 10 seconds.
(f) Coating.......................  (1) The pipe must be protected
                                     against external corrosion by a non-
                                     shielding coating.
                                    (2) Coating on pipe used for
                                     trenchless installation must be non-
                                     shielding and resist abrasions and
                                     other damage possible during
                                     installation.
                                    (3) A quality assurance inspection
                                     and testing program for the coating
                                     must cover the surface quality of
                                     the bare pipe, surface cleanliness
                                     and chlorides, blast cleaning,
                                     application temperature control,
                                     adhesion, cathodic disbondment,
                                     moisture permeation, bending,
                                     coating thickness, holiday
                                     detection, and repair.
(g) Fittings and flanges..........  (1) There must be certification
                                     records of flanges, factory
                                     induction bends and factory weld
                                     ells. Certification must address
                                     material properties such as
                                     chemistry, minimum yield strength
                                     and minimum wall thickness to meet
                                     design conditions.
                                    (2) If the carbon equivalents of
                                     flanges, bends and ells are greater
                                     than 0.42 percent by weight, the
                                     qualified welding procedures must
                                     include a pre-heat procedure.
                                    (3) Valves, flanges and fittings
                                     must be rated based upon the
                                     required specification rating class
                                     for the alternative MAOP.
(h) Compressor stations...........  (1) A compressor station must be
                                     designed to limit the temperature
                                     of the nearest downstream segment
                                     operating at alternative MAOP to a
                                     maximum of 120 degrees Fahrenheit
                                     (49 degrees Celsius) or the higher
                                     temperature allowed in paragraph
                                     (h)(2) of this section unless a
                                     long-term coating integrity
                                     monitoring program is implemented
                                     in accordance with paragraph (h)(3)
                                     of this section.
                                    (2) If research, testing and field
                                     monitoring tests demonstrate that
                                     the coating type being used will
                                     withstand a higher temperature in
                                     long-term operations, the
                                     compressor station may be designed
                                     to limit downstream piping to that
                                     higher temperature. Test results
                                     and acceptance criteria addressing
                                     coating adhesion, cathodic
                                     disbondment, and coating condition
                                     must be provided to each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service at
                                     least 60 days prior to operating
                                     above 120 degrees Fahrenheit (49
                                     degrees Celsius). 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.
                                    (3) Pipeline segments operating at
                                     alternative MAOP may operate at
                                     temperatures above 120 degrees
                                     Fahrenheit (49 degrees Celsius) if
                                     the operator implements a long-term
                                     coating integrity monitoring
                                     program. The monitoring program
                                     must include examinations using
                                     direct current voltage gradient
                                     (DCVG), alternating current voltage
                                     gradient (ACVG), or an equivalent
                                     method of monitoring coating
                                     integrity. An operator must specify
                                     the periodicity at which these
                                     examinations occur and criteria for
                                     repairing identified indications.
                                     An operator must submit its long-
                                     term coating integrity monitoring
                                     program to each PHMSA pipeline
                                     safety regional office in which the
                                     pipeline is located for review
                                     before the pipeline segments may be
                                     operated at temperatures in excess
                                     of 120 degrees Fahrenheit (49
                                     degrees Celsius). 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.
------------------------------------------------------------------------


0
4. Add Sec.  192.328 to subpart G to read as follows:


Sec.  192.328  Additional construction requirements for steel pipe 
using alternative maximum allowable operating pressure.

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure calculated 
under Sec.  192.620, a segment must meet the following additional 
construction requirements. Records must be maintained, for the useful 
life of the pipeline, demonstrating compliance with these requirements:

[[Page 62177]]



------------------------------------------------------------------------
   To address this construction      The pipeline segment must meet this
              issue:                additional construction requirement:
------------------------------------------------------------------------
 (a) Quality assurance............   (1) The construction of the
                                     pipeline segment must be done under
                                     a quality assurance plan addressing
                                     pipe inspection, hauling and
                                     stringing, field bending, welding,
                                     non-destructive examination of
                                     girth welds, applying and testing
                                     field applied coating, lowering of
                                     the pipeline into the ditch,
                                     padding and backfilling, and
                                     hydrostatic testing.
                                    (2) The quality assurance plan for
                                     applying and testing field applied
                                     coating to girth welds must be:
                                    (i) Equivalent to that required
                                     under Sec.   192.112(f)(3) for
                                     pipe; and
                                    (ii) Performed by an individual with
                                     the knowledge, skills, and ability
                                     to assure effective coating
                                     application.
 (b) Girth welds..................   (1) All girth welds on a new
                                     pipeline segment must be non-
                                     destructively examined in
                                     accordance with Sec.   192.243(b)
                                     and (c).
 (c) Depth of cover...............   (1) Notwithstanding any lesser
                                     depth of cover otherwise allowed in
                                     Sec.   192.327, there must be at
                                     least 36 inches (914 millimeters)
                                     of cover or equivalent means to
                                     protect the pipeline from outside
                                     force damage.
                                    (2) In areas where deep tilling or
                                     other activities could threaten the
                                     pipeline, the top of the pipeline
                                     must be installed at least one foot
                                     below the deepest expected
                                     penetration of the soil.
 (d) Initial strength testing.....   (1) The pipeline segment must not
                                     have experienced failures
                                     indicative of systemic material
                                     defects during strength testing,
                                     including initial hydrostatic
                                     testing. A root cause analysis,
                                     including metallurgical examination
                                     of the failed pipe, must be
                                     performed for any failure
                                     experienced to verify that it is
                                     not indicative of a systemic
                                     concern. The results of this root
                                     cause analysis must be reported to
                                     each PHMSA pipeline safety regional
                                     office where the pipe is in service
                                     at least 60 days prior to operating
                                     at the alternative MAOP. 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.
 (e) Interference currents........   (1) For a new pipeline segment, the
                                     construction must address the
                                     impacts of induced alternating
                                     current from parallel electric
                                     transmission lines and other known
                                     sources of potential interference
                                     with corrosion control.
------------------------------------------------------------------------



0
5. Amend Sec.  192.611 by revising paragraph (a)(1) and (a)(3)(i) and 
(ii) and adding new paragraph (a)(3)(iii) to read as follows:


Sec.  192.611  Change in class location: Confirmation or revision of 
maximum allowable operating pressure.

    (a) * * *
    (1) If the segment involved has been previously tested in place for 
a period of not less than 8 hours:
    (i) The maximum allowable operating pressure is 0.8 times the test 
pressure in Class 2 locations, 0.667 times the test pressure in Class 3 
locations, or 0.555 times the test pressure in Class 4 locations. The 
corresponding hoop stress may not exceed 72 percent of the SMYS of the 
pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 
50 percent of SMYS in Class 4 locations.
    (ii) The alternative maximum allowable operating pressure is 0.8 
times the test pressure in Class 2 locations and 0.667 times the test 
pressure in Class 3 locations. For pipelines operating at alternative 
maximum allowable pressure per Sec.  192.620, the corresponding hoop 
stress may not exceed 80 percent of the SMYS of the pipe in Class 2 
locations and 67 percent of SMYS in Class 3 locations.
* * * * *
    (3) * * *
    (i) The maximum allowable operating pressure after the 
requalification test is 0.8 times the test pressure for Class 2 
locations, 0.667 times the test pressure for Class 3 locations, and 
0.555 times the test pressure for Class 4 locations.
    (ii) The corresponding hoop stress may not exceed 72 percent of the 
SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 
locations, or 50 percent of SMYS in Class 4 locations.
    (iii) For pipeline operating at an alternative maximum allowable 
operating pressure per Sec.  192.620, the alternative maximum allowable 
operating pressure after the requalification test is 0.8 times the test 
pressure for Class 2 locations and 0.667 times the test pressure for 
Class 3 locations. The corresponding hoop stress may not exceed 80 
percent of the SMYS of the pipe in Class 2 locations and 67 percent of 
SMYS in Class 3 locations.
* * * * *

0
6. Amend Sec.  192.619 by revising paragraph (a) introductory text and 
by adding paragraph (d) to read as follows:


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

    (a) No person may operate a segment of steel or plastic pipeline at 
a pressure that exceeds a maximum allowable operating pressure 
determined under paragraph (c) or (d) of this section, or the lowest of 
the following:
* * * * *
    (d) The operator of a pipeline segment of steel pipeline meeting 
the conditions prescribed in Sec.  192.620(b) may elect to operate the 
segment at a maximum allowable operating pressure determined under 
Sec.  192.620(a).


0
7. Add Sec.  192.620 to subpart L to read as follows:


Sec.  192.620  Alternative maximum allowable operating pressure for 
certain steel pipelines.

    (a) How does an operator calculate the alternative maximum 
allowable operating pressure? An operator calculates the alternative 
maximum allowable operating pressure by using different factors in the 
same formulas used for calculating maximum allowable operating pressure 
under Sec.  192.619(a) as follows:
    (1) In determining the alternative design pressure under Sec.  
192.105, use a design factor determined in accordance with Sec.  
192.111(b), (c), or (d) or, if none of these paragraphs apply, in 
accordance with the following table:

------------------------------------------------------------------------
                                                            Alternative
                     Class location                        design factor
                                                                (F)
------------------------------------------------------------------------
 1......................................................            0.80
 2......................................................            0.67
 3......................................................            0.56
------------------------------------------------------------------------

    (i) For facilities installed prior to November 17, 2008, for which 
Sec.  192.111(b), (c), or (d) apply, use the following design factors 
as alternatives for the factors specified in those paragraphs: Sec.  
192.111(b)--0.67 or less; 192.111(c) and (d)--0.56 or less.
    (ii) [Reserved]
    (2) The alternative maximum allowable operating pressure is the 
lower of the following:
    (i) The design pressure of the weakest element in the pipeline 
segment, determined under subparts C and D of this part.
    (ii) The pressure obtained by dividing the pressure to which the 
pipeline segment was tested after construction by

[[Page 62178]]

a factor determined in the following table:

------------------------------------------------------------------------
                                                            Alternative
                     Class location                         test factor
------------------------------------------------------------------------
 1......................................................            1.25
 2......................................................        \1\ 1.50
 3......................................................            1.50
------------------------------------------------------------------------
\1\ For Class 2 alternative maximum allowable operating pressure
  segments installed prior to November 17, 2008, the alternative test
  factor is 1.25.

    (b) When may an operator use the alternative maximum allowable 
operating pressure calculated under paragraph (a) of this section? An 
operator may use an alternative maximum allowable operating pressure 
calculated under paragraph (a) of this section if the following 
conditions are met:
    (1) The pipeline segment is in a Class 1, 2, or 3 location;
    (2) The pipeline segment is constructed of steel pipe meeting the 
additional design requirements in Sec.  192.112;
    (3) A supervisory control and data acquisition system provides 
remote monitoring and control of the pipeline segment. The control 
provided must include monitoring of pressures and flows, monitoring 
compressor start-ups and shut-downs, and remote closure of valves;
    (4) The pipeline segment meets the additional construction 
requirements described in Sec.  192.328;
    (5) The pipeline segment does not contain any mechanical couplings 
used in place of girth welds;
    (6) If a pipeline segment has been previously operated, the segment 
has not experienced any failure during normal operations indicative of 
a systemic fault in material as determined by a root cause analysis, 
including metallurgical examination of the failed pipe. The results of 
this root cause analysis must be reported to each PHMSA pipeline safety 
regional office where the pipeline is in service at least 60 days prior 
to operation at the alternative MAOP. An operator must also notify a 
State pipeline safety authority when the pipeline is located in a State 
where PHMSA has an interstate agent agreement, or an intrastate 
pipeline is regulated by that State; and
    (7) At least 95 percent of girth welds on a segment that was 
constructed prior to November 17, 2008, must have been non-
destructively examined in accordance with Sec.  192.243(b) and (c).
    (c) What is an operator electing to use the alternative maximum 
allowable operating pressure required to do? If an operator elects to 
use the alternative maximum allowable operating pressure calculated 
under paragraph (a) of this section for a pipeline segment, the 
operator must do each of the following:
    (1) Notify each PHMSA pipeline safety regional office where the 
pipeline is in service of its election with respect to a segment at 
least 180 days before operating at the alternative maximum allowable 
operating pressure. 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.
    (2) Certify, by signature of a senior executive officer of the 
company, as follows:
    (i) The pipeline segment meets the conditions described in 
paragraph (b) of this section; and
    (ii) The operating and maintenance procedures include the 
additional operating and maintenance requirements of paragraph (d) of 
this section; and
    (iii) The review and any needed program upgrade of the damage 
prevention program required by paragraph (d)(4)(v) of this section has 
been completed.
    (3) Send a copy of the certification required by paragraph (c)(2) 
of this section to each PHMSA pipeline safety regional office where the 
pipeline is in service 30 days prior to operating at the alternative 
MAOP. An operator must also send a copy to a State pipeline safety 
authority when the pipeline is located in a State where PHMSA has an 
interstate agent agreement, or an intrastate pipeline is regulated by 
that State.
    (4) For each pipeline segment, do one of the following:
    (i) Perform a strength test as described in Sec.  192.505 at a test 
pressure calculated under paragraph (a) of this section or
    (ii) For a pipeline segment in existence prior to November 17, 
2008, certify, under paragraph (c)(2) of this section, that the 
strength test performed under Sec.  192.505 was conducted at a test 
pressure calculated under paragraph (a) of this section, or conduct a 
new strength test in accordance with paragraph (c)(4)(i) of this 
section.
    (5) Comply with the additional operation and maintenance 
requirements described in paragraph (d) of this section.
    (6) If the performance of a construction task associated with 
implementing alternative MAOP can affect the integrity of the pipeline 
segment, treat that task as a ``covered task'', notwithstanding the 
definition in Sec.  192.801(b) and implement the requirements of 
subpart N as appropriate.
    (7) Maintain, for the useful life of the pipeline, records 
demonstrating compliance with paragraphs (b), (c)(6), and (d) of this 
section.
    (8) A Class 1 and Class 2 pipeline location can be upgraded one 
class due to class changes per Sec.  192.611(a)(3)(i). All class 
location changes from Class 1 to Class 2 and from Class 2 to Class 3 
must have all anomalies evaluated and remediated per: The ``original 
pipeline class grade'' Sec.  192.620(d)(11) anomaly repair 
requirements; and all anomalies with a wall loss equal to or greater 
than 40 percent must be excavated and remediated. Pipelines in Class 4 
may not operate at an alternative MAOP.
    (d) What additional operation and maintenance requirements apply to 
operation at the alternative maximum allowable operating pressure? In 
addition to compliance with other applicable safety standards in this 
part, if an operator establishes a maximum allowable operating pressure 
for a pipeline segment under paragraph (a) of this section, an operator 
must comply with the additional operation and maintenance requirements 
as follows:

------------------------------------------------------------------------
  To address increased risk of a
    maximum allowable operating
  pressure based on higher stress    Take the following additional step:
  levels in the following areas:
------------------------------------------------------------------------
(1) Identifying and evaluating      Develop a threat matrix consistent
 threats.                            with Sec.   192.917 to do the
                                     following:
                                    (i) Identify and compare the
                                     increased risk of operating the
                                     pipeline at the increased stress
                                     level under this section with
                                     conventional operation; and
                                    (ii) Describe and implement
                                     procedures used to mitigate the
                                     risk.
(2) Notifying the public..........  (i) Recalculate the potential impact
                                     circle as defined in Sec.   192.903
                                     to reflect use of the alternative
                                     maximum operating pressure
                                     calculated under paragraph (a) of
                                     this section and pipeline operating
                                     conditions; and
                                    (ii) In implementing the public
                                     education program required under
                                     Sec.   192.616, perform the
                                     following:

[[Page 62179]]

 
                                    (A) Include persons occupying
                                     property within 220 yards of the
                                     centerline and within the potential
                                     impact circle within the targeted
                                     audience; and
                                    (B) Include information about the
                                     integrity management activities
                                     performed under this section within
                                     the message provided to the
                                     audience.
(3) Responding to an emergency in   (i) Ensure that the identification
 an area defined as a high           of high consequence areas reflects
 consequence area in Sec.            the larger potential impact circle
 192.903.                            recalculated under paragraph
                                     (d)(1)(i) of this section.
                                    (ii) If personnel response time to
                                     mainline valves on either side of
                                     the high consequence area exceeds
                                     one hour (under normal driving
                                     conditions and speed limits) from
                                     the time the event is identified in
                                     the control room, provide remote
                                     valve control through a supervisory
                                     control and data acquisition
                                     (SCADA) system, other leak
                                     detection system, or an alternative
                                     method of control.
                                    (iii) Remote valve control must
                                     include the ability to close and
                                     monitor the valve position (open or
                                     closed), and monitor pressure
                                     upstream and downstream.
                                    (iv) A line break valve control
                                     system using differential pressure,
                                     rate of pressure drop or other
                                     widely-accepted method is an
                                     acceptable alternative to remote
                                     valve control.
(4) Protecting the right-of-way...  (i) Patrol the right-of-way at
                                     intervals not exceeding 45 days,
                                     but at least 12 times each calendar
                                     year, to inspect for excavation
                                     activities, ground movement, wash
                                     outs, leakage, or other activities
                                     or conditions affecting the safety
                                     operation of the pipeline.
                                    (ii) Develop and implement a plan to
                                     monitor for and mitigate
                                     occurrences of unstable soil and
                                     ground movement.
                                    (iii) If observed conditions
                                     indicate the possible loss of
                                     cover, perform a depth of cover
                                     study and replace cover as
                                     necessary to restore the depth of
                                     cover or apply alternative means to
                                     provide protection equivalent to
                                     the originally-required depth of
                                     cover.
                                    (iv) Use line-of-sight line markers
                                     satisfying the requirements of Sec.
                                       192.707(d) except in agricultural
                                     areas, large water crossings or
                                     swamp, steep terrain, or where
                                     prohibited by Federal Energy
                                     Regulatory Commission orders,
                                     permits, or local law.
                                    (v) Review the damage prevention
                                     program under Sec.   192.614(a) in
                                     light of national consensus
                                     practices, to ensure the program
                                     provides adequate protection of the
                                     right-of-way. Identify the
                                     standards or practices considered
                                     in the review, and meet or exceed
                                     those standards or practices by
                                     incorporating appropriate changes
                                     into the program.
                                    (vi) Develop and implement a right-
                                     of-way management plan to protect
                                     the pipeline segment from damage
                                     due to excavation activities.
(5) Controlling internal corrosion  (i) Develop and implement a program
                                     to monitor for and mitigate the
                                     presence of, deleterious gas stream
                                     constituents.
                                    (ii) At points where gas with
                                     potentially deleterious
                                     contaminants enters the pipeline,
                                     use filter separators or separators
                                     and gas quality monitoring
                                     equipment.
                                    (iii) Use gas quality monitoring
                                     equipment that includes a moisture
                                     analyzer, chromatograph, and
                                     periodic hydrogen sulfide sampling.
                                    (iv) Use cleaning pigs and
                                     inhibitors, and sample accumulated
                                     liquids when corrosive gas is
                                     present.
                                    (v) Address deleterious gas stream
                                     constituents as follows:
                                    (A) Limit carbon dioxide to 3
                                     percent by volume;
                                    (B) Allow no free water and
                                     otherwise limit water to seven
                                     pounds per million cubic feet of
                                     gas; and
                                    (C) Limit hydrogen sulfide to 1.0
                                     grain per hundred cubic feet (16
                                     ppm) of gas, where the hydrogen
                                     sulfide is greater than 0.5 grain
                                     per hundred cubic feet (8 ppm) of
                                     gas, implement a pigging and
                                     inhibitor injection program to
                                     address deleterious gas stream
                                     constituents, including follow-up
                                     sampling and quality testing of
                                     liquids at receipt points.
                                    (vi) Review the program at least
                                     quarterly based on the gas stream
                                     experience and implement
                                     adjustments to monitor for, and
                                     mitigate the presence of,
                                     deleterious gas stream
                                     constituents.
(6) Controlling interference that   (i) Prior to operating an existing
 can impact external corrosion.      pipeline segment at an alternate
                                     maximum allowable operating
                                     pressure calculated under this
                                     section, or within six months after
                                     placing a new pipeline segment in
                                     service at an alternate maximum
                                     allowable operating pressure
                                     calculated under this section,
                                     address any interference currents
                                     on the pipeline segment.
                                    (ii) To address interference
                                     currents, perform the following:
                                    (A) Conduct an interference survey
                                     to detect the presence and level of
                                     any electrical current that could
                                     impact external corrosion where
                                     interference is suspected;
                                    (B) Analyze the results of the
                                     survey; and
                                    (C) Take any remedial action needed
                                     within 6 months after completing
                                     the survey to protect the pipeline
                                     segment from deleterious current.
(7) Confirming external corrosion   (i) Within six months after placing
 control through indirect            the cathodic protection of a new
 assessment.                         pipeline segment in operation, or
                                     within six months after certifying
                                     a segment under Sec.
                                     192.620(c)(1) of an existing
                                     pipeline segment under this
                                     section, assess the adequacy of the
                                     cathodic protection through an
                                     indirect method such as close-
                                     interval survey, and the integrity
                                     of the coating using direct current
                                     voltage gradient (DCVG) or
                                     alternating current voltage
                                     gradient (ACVG).
                                    (ii) Remediate any construction
                                     damaged coating with a voltage drop
                                     classified as moderate or severe
                                     (IR drop greater than 35% for DCVG
                                     or 50 dB[mu]v for ACVG) under
                                     section 4 of NACE RP-0502-2002
                                     (incorporated by reference, see
                                     Sec.   192.7).
                                    (iii) Within six months after
                                     completing the baseline internal
                                     inspection required under paragraph
                                     (8) of this section, integrate the
                                     results of the indirect assessment
                                     required under paragraph (6)(i) of
                                     this section with the results of
                                     the baseline internal inspection
                                     and take any needed remedial
                                     actions.
                                    (iv) For all pipeline segments in
                                     high consequence areas, perform
                                     periodic assessments as follows:

[[Page 62180]]

 
                                    (A) Conduct periodic close interval
                                     surveys with current interrupted to
                                     confirm voltage drops in
                                     association with periodic
                                     assessments under subpart O of this
                                     part.
                                    (B) Locate pipe-to-soil test
                                     stations at half-mile intervals
                                     within each high consequence area
                                     ensuring at least one station is
                                     within each high consequence area,
                                     if practicable.
                                    (C) Integrate the results with those
                                     of the baseline and periodic
                                     assessments for integrity done
                                     under paragraphs (d)(8) and (d)(9)
                                     of this section.
(8) Controlling external corrosion  (i) If an annual test station
 through cathodic protection.        reading indicates cathodic
                                     protection below the level of
                                     protection required in subpart I of
                                     this part, complete remedial action
                                     within six months of the failed
                                     reading or notify each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service
                                     demonstrating that the integrity of
                                     the pipeline is not compromised if
                                     the repair takes longer than 6
                                     months. An operator must also
                                     notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State; and
                                    (ii) After remedial action to
                                     address a failed reading, confirm
                                     restoration of adequate corrosion
                                     control by a close interval survey
                                     on either side of the affected test
                                     station to the next test station.
                                    (iii) If the pipeline segment has
                                     been in operation, the cathodic
                                     protection system on the pipeline
                                     segment must have been operational
                                     within 12 months of the completion
                                     of construction.
(9) Conducting a baseline           (i) Except as provided in paragraph
 assessment of integrity.            (d)(8)(iii) of this section, for a
                                     new pipeline segment operating at
                                     the new alternative maximum
                                     allowable operating pressure,
                                     perform a baseline internal
                                     inspection of the entire pipeline
                                     segment as follows:
                                    (A) Assess using a geometry tool
                                     after the initial hydrostatic test
                                     and backfill and within six months
                                     after placing the new pipeline
                                     segment in service; and
                                    (B) Assess using a high resolution
                                     magnetic flux tool within three
                                     years after placing the new
                                     pipeline segment in service at the
                                     alternative maximum allowable
                                     operating pressure.
                                    (ii) Except as provided in paragraph
                                     (d)(8)(iii) of this section, for an
                                     existing pipeline segment, perform
                                     a baseline internal assessment
                                     using a geometry tool and a high
                                     resolution magnetic flux tool
                                     before, but within two years prior
                                     to, raising pressure to the
                                     alternative maximum allowable
                                     operating pressure as allowed under
                                     this section.
                                    (iii) If headers, mainline valve by-
                                     passes, compressor station piping,
                                     meter station piping, or other
                                     short portion of a pipeline segment
                                     operating at alternative maximum
                                     allowable operating pressure cannot
                                     accommodate a geometry tool and a
                                     high resolution magnetic flux tool,
                                     use direct assessment (per Sec.
                                     192.925, Sec.   192.927 and/or Sec.
                                       192.929) or pressure testing (per
                                     subpart J of this part) to assess
                                     that portion.
(10) Conducting periodic            (i) Determine a frequency for
 assessments of integrity.           subsequent periodic integrity
                                     assessments as if all the
                                     alternative maximum allowable
                                     operating pressure pipeline
                                     segments were covered by subpart O
                                     of this part and
                                    (ii) Conduct periodic internal
                                     inspections using a high resolution
                                     magnetic flux tool on the frequency
                                     determined under paragraph
                                     (d)(9)(i) of this section, or
                                    (iii) Use direct assessment (per
                                     Sec.   192.925, Sec.   192.927 and/
                                     or Sec.   192.929) or pressure
                                     testing (per subpart J of this
                                     part) for periodic assessment of a
                                     portion of a segment to the extent
                                     permitted for a baseline assessment
                                     under paragraph (d)(8)(iii) of this
                                     section.
(11) Making repairs...............  (i) Perform the following when
                                     evaluating an anomaly:
                                    (A) Use the most conservative
                                     calculation for determining
                                     remaining strength or an
                                     alternative validated calculation
                                     based on pipe diameter, wall
                                     thickness, grade, operating
                                     pressure, operating stress level,
                                     and operating temperature: and
                                    (B) Take into account the tolerances
                                     of the tools used for the
                                     inspection.
                                    (ii) Repair a defect immediately if
                                     any of the following apply:
                                    (A) The defect is a dent discovered
                                     during the baseline assessment for
                                     integrity under paragraph (d)(8) of
                                     this section and the defect meets
                                     the criteria for immediate repair
                                     in Sec.   192.309(b).
                                    (B) The defect meets the criteria
                                     for immediate repair in Sec.
                                     192.933(d).
                                    (C) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.67
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.25 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (D) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.56
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than or equal to 1.4 times the
                                     alternative maximum allowable
                                     operating pressure.
                                    (iii) If paragraph (d)(10)(ii) of
                                     this section does not require
                                     immediate repair, repair a defect
                                     within one year if any of the
                                     following apply:
                                    (A) The defect meets the criteria
                                     for repair within one year in Sec.
                                      192.933(d).
                                    (B) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.80
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.25 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (C) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.67
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.50 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (D) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.56
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than or equal to 1.80 times the
                                     alternative maximum allowable
                                     operating pressure.
                                    (iv) Evaluate any defect not
                                     required to be repaired under
                                     paragraph (d)(10)(ii) or (iii) of
                                     this section to determine its
                                     growth rate, set the maximum
                                     interval for repair or re-
                                     inspection, and repair or re-
                                     inspect within that interval.
------------------------------------------------------------------------


[[Page 62181]]

    (e) Is there any change in overpressure protection associated with 
operating at the alternative maximum allowable operating pressure? 
Notwithstanding the required capacity of pressure relieving and 
limiting stations otherwise required by Sec.  192.201, if an operator 
establishes a maximum allowable operating pressure for a pipeline 
segment in accordance with paragraph (a) of this section, an operator 
must:
    (1) Provide overpressure protection that limits mainline pressure 
to a maximum of 104 percent of the maximum allowable operating 
pressure; and
    (2) Develop and follow a procedure for establishing and maintaining 
accurate set points for the supervisory control and data acquisition 
system.

    Issued in Washington, DC, on October 2, 2008.
Carl T. Johnson,
Administrator.
[FR Doc. E8-23915 Filed 10-16-08; 8:45 am]
BILLING CODE 4910-60-P


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