[Federal Register: March 12, 2008 (Volume 73, Number 49)]
[Proposed Rules]
[Page 13167-13185]
[DOCID:fr12mr08-45]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket ID PHMSA-2005-23447; Notice 2]
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

ACTION: Notice of proposed rulemaking.

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SUMMARY: PHMSA proposes to amend the pipeline safety regulations to
prescribe safety requirements for the operation of certain gas
transmission pipelines at pressures based on higher stress levels. The
result would be an increase of maximum allowable operating pressure
(MAOP) over that currently allowed in the regulations. This action
would update regulatory standards to reflect improvements in pipeline
materials, assessment tools, and maintenance practices, which together
have significantly reduced the risk of failure in steel pipeline
fabricated and installed over the last twenty-five years. The proposed
rule would allow use of an established industry standard for the
calculation of

MAOP, but limit application of the standard to pipelines posing a low
safety risk based on location, materials, and construction. The
proposed rule would generate significant public benefits by boosting
the potential capacity and efficiency of pipeline infrastructure, while
promoting investment in improved pipe technology and rigorous life-
cycle maintenance.

DATES: Anyone interested in filing written comments on the rule
proposed in this document must do so by May 12, 2008. PHMSA will
consider late filed comments so far as practicable.

ADDRESSES: Comments should reference Docket ID PHMSA-2005-23447 and may
be submitted in the following ways:
     E-Gov Web Site: http://www.regulations.gov. This site
allows the public to enter comments on any Federal Register notice
issued by any agency. Follow the instructions for submitting comments.
     Fax: 1-202-493-2251.
     Mail: Docket Management System: U.S. Department of
Transportation, 1200 New Jersey Avenue, SE., Room W12-140, Washington,
DC 20590.
     Hand Delivery: DOT Docket Management System; Room W12-140,
on the ground floor of the West Building, 1200 New Jersey Avenue, SE.,
Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except
Federal holidays.
    Instructions: Identify the docket ID, PHMSA-2005-23447, at the
beginning of your comments. If you submit your comments by mail, submit
two copies. If you wish to receive confirmation that PHMSA received
your comments, include a self-addressed stamped postcard. Internet
users may submit comments at http://www.regulations.gov.

    Note: Comments will be posted without changes or edits to http:/
/www.regulations.gov including any personal information provided.
Please see the Privacy Act heading in the Regulatory Analyses and
Notices section of the Supplemental Information for additional
information.

FOR FURTHER INFORMATION CONTACT: For information about this rulemaking,
contact Barbara Betsock by phone at<PHONE_NUMBER>, by fax at (202)
366-4566, or by e-mail at<EMAIL_ADDRESS>For technical
information, contact Alan Mayberry by phone at<PHONE_NUMBER>, or by e-
mail at<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

A. Purpose of the Rulemaking
B. Background
    B.1. Current Regulations
    B.2. Evolution in Views on Pressure
    B.3. History of PHMSA Consideration
    B.4. Safety Conditions in Special Permits
    B.5. Codifying the Special Permits
    B.6. How to Handle Special Permits and Requests for Special
Permits
    B.7. Statutory Considerations
C. The Proposed Rule
    C.1. In General
    C.2. Proposed Amendment to Sec.  192.7--Incorporation by
Reference
    C.3. Proposed New Sec.  192.112--Additional Design Requirements
    C.4. Proposed New Sec.  192.328--Additional Construction
Requirements
    C.5. Proposed Amendment to Sec.  192.619--Maximum Allowable
Operating Pressure
    C.6. Proposed New Sec.  192.620--Operation at an Alternative
MAOP
    C.6.1. Calculating the Alternative MAOP
    C.6.2. Which Pipelines Qualify
    C.6.3. How an Operator Selects Operation Under This Section
    C.6.4. Initial Strength Testing
    C.6.5. Operation and Maintenance
    C.6.6. New Construction and Maintenance Tasks
    C.6.7. Recordkeeping
C.7. Additional Operation and Maintenance Requirements
    C.7.1. Threat Assessments
    C.7.2. Public Awareness
    C.7.3. Emergency Response
    C.7.4. Damage Prevention
    C.7.5. Internal Corrosion Control
    C.7.6. External Corrosion Control
    C.7.7. Integrity Assessments
    C.7.8. Repair Criteria
C.8. Overpressure Protection--Proposed Sec.  192.620(e)
D. Regulatory Analyses and Notices
    D.1. Privacy Act Statement
    D.2. Executive Order 12866 and DOT Policies and Procedures
    D.3. Regulatory Flexibility Act
    D.4. Executive Order 13175
    D.5. Paperwork Reduction Act
    D.6. Unfunded Mandates Reform Act of 1995
    D.7. National Environmental Policy Act
    D.8. Executive Order 13132
    D.9. Executive Order 13211

A. Purpose of the Rulemaking

    The regulatory relief proposed in this rulemaking is made possible
by dramatic improvements in pipeline technology and risk controls over
the past 25 years. The current standards for calculating maximum
allowable operating pressure (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 of how to reduce pipeline risks. In view of
these developments, PHMSA believes 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.
    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 design requirements. These special permits
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 developed in the special permit
proceedings, PHMSA now proposes to codify the conditions and
limitations of the special permits into standards of general
applicability.

B. Background

B.1. Current Regulations

    The design factor specified in Sec.  192.105 restricts the MAOP of
a steel gas transmission pipeline based on stress levels and class
location. For most steel pipelines, the MAOP is defined in Sec.
192.619 based on design pressure calculated using a formula, found at
Sec.  192.111, that includes the design factor. 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 (but not

to exceed 80 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'' (68 FR 69816).
Integrity management programs, as described in subpart O of part 192,
include threat assessments, both baseline and periodic internal
inspection or direct assessment, and additional measures designed to
prevent and mitigate pipeline failures and their consequences. A high
consequence area, 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.
For purposes of risk analysis, the regulations establish four
classifications based on population density, ranging from Class 1
(undeveloped, rural land) through Class 4 (densely populated urban
areas). In addition to class location, one of the criteria for
identifying a high consequence area 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, steel pipe can
last for decades in gas service. However, the manufacture of the steel
or casting of the pipe can introduce flaws. In addition, during
construction, improper backfilling can damage pipe coating. Over time,
damaged coating can allow corrosion to continue unchecked and cause
leaks. During operation, excavators' substandard practices can dent the
line or corrosion can thin the wall of the pipe.
    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 over 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 solution 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, 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 removed defects. In 1968, the
American Gas Association published Report No. L30050 entitled Study of
Feasibility of Basing Natural Gas Pipeline Operating Pressure on
Hydrostatic Test Pressure prepared by the Battelle Memorial Institute.
The research study concluded that:
     It is inherently safer to base the MAOP on the test
pressure, which demonstrates the actual in-place yield strength of the
pipeline, than to base it on SMYS alone.
     High pressure hydrostatic testing is able to remove
defects that may fail in service.
     Hydrostatic testing to actual yield, as determined with a
pressure-volume plot, does not damage a pipeline.
    The report specifically recommended setting the MAOP as a
percentage of the field test pressure. In particular, it recommended
setting the MAOP at 80 percent of the test pressure when the minimum
test pressure is 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 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 manufacture provide engineers considerable
information about their material properties. The toughness standards
make the 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 one type of defect pressure testing
cannot identify is a flaw in a girth weld. Such defects are detectable
though pre-operational non-destructive testing, which this proposed
rule would require.
    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, they each provide 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 inline
inspection 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 has never formally revisited its part 192 MAOP
standards, developments in related arenas have increasingly set the
stage for the more limited action we propose here. 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 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 include 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 waivers do not address increases in stress levels, they do
address many of the same concerns by looking at how to handle the risks
caused by operating pressure. Many of the specific criteria, and
certainly the approach to risk management in the class location
waivers, helped PHMSA develop the approach to the special permits
discussed below and, ultimately, to this proposed 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. 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
during these efforts overwhelmingly support examining increased MAOP as
a way to increase energy efficiency and capacity without reducing
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 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
experience with pipelines operating at stress levels higher than 72
percent of SMYS:
     About 6,000 miles of pipelines on the Alberta system,
ranging from 6 to 42 inches in diameter, installed or upgraded between
the early 1970s and 2005;
     About 4,500 miles of pipelines on the Mainline system east
of the Alberta-Saskatchewan border, ranging from 20 to 42 inches in
diameter, installed or upgraded between the early 1970s and 2005; and
     More than 600 miles in the Foothills Pipe Line system,
ranging from 36 to 40 inches in diameter, installed between 1979 and
1998.
    In the United Kingdom, about 1,140 miles of the Northern pipeline
system has been uprated to operate at higher stress level in the past
ten years.
    In the United States, some 5,000 miles of gas transmission lines
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 pipeline's
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 corrects 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 earlier this 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 helps 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 also
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, PHMSA established a docket and sought
public comment on the request. We received few public comments, most in
response to the first special permits considered. Many of the comments
supported granting the special permits. Those who did not may have been
unappreciative of the significance of the safety upgrades required for
the special permits. A few 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 comment addressed concerns, such as compensation or
aesthetics, which were outside the scope of the special permits. PHMSA
permits do not address issues on siting, which is governed by the
Federal Energy Regulatory Commission.
    PHMSA has now issued several special permits in response to these
requests and continues to receive and evaluate other requests. The
following table identifies the status of special permit requests and
the dockets containing additional information about them.

                  Table B.4.--Status of Special Permits
------------------------------------------------------------------------
        Docket ID PHMSA--          Status of request         Type
------------------------------------------------------------------------
2005-23448, Maritimes &           Granted, July 11,   Pipeline in
 Northeast Pipeline (Spectra       2006.               operation since
 Energy).                                              1999.
2005-23387, Alliance Pipeline...  Granted, July 11,   Pipeline in
                                   2006.               operation since
                                                       2000.
2006-23998, Rockies Express       Granted, July 11,   New pipeline.
 Pipeline.                         2006.
2006-25803, Kinder Morgan         Granted, April 19,  New pipeline.
 Louisiana Pipeline.               2007.
2006-25802, CenterPoint Energy    Granted, July 18,   New pipeline.
 Gas Transmission.                 2007.
2006-26533, Gulf South Pipeline.  Granted, August     New pipeline.
                                   24, 2007.
2006-26616, Ozark Gas             Pending...........  New pipeline.
 Transmission.
2006-27607, Southeast Supply      Pending...........  New pipeline.
 Header.
2006-27842, Midcontinent Express  Pending...........  New pipeline.
 (Kinder Morgan).
2007-27121, Transwestern          Pending...........  Pipeline in
 Pipeline.                                             operation since
                                                       1992 and 2005.
2007-28994, Gulf South Pipeline   Pending...........  New pipeline.
 (SouthEast Expansion Project).
2007-29078, Kern River Gas        Pending...........  Pipeline in
 Transmission Company.                                 operation since
                                                       1992.
------------------------------------------------------------------------

    In each case, PHMSA provides oversight to confirm the line pipe is,
or will be, 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 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 be able to demonstrate
that the pipeline has been built to rigorous design and construction
standards. These additional design and construction standards focus 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 more resistant to expected operational risks. In addition, the
operator of a pipeline receiving a special permit must comply with
operation and maintenance requirements that exceed current pipeline
safety regulations. These additional operation and maintenance
requirements focus on the potential for corrosion and mechanical damage
and on detecting defects before the defects can grow to failure.

B.5. Codifying the Special Permits

    This proposed rule would put in place a process for managing the
life cycle of a pipeline operating at a higher stress level. Integrity
management focuses on managing and extending the service life of the
pipeline. Life-cycle management goes beyond the operations and
maintenance practices, including integrity management, to address steel
production, pipeline manufacture, pipeline design, and installation.
    Industry experience with integrity management demonstrates the
value of life-cycle maintenance. 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 General
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 proposed rule, pipelines will be
designed and constructed under more rigorous conditions. Baseline
assessment of these lines as proposed 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 proposed rule, based on the terms and conditions of the
special permits allowing operation at higher stress levels, would
impose similar terms and conditions and limitations on operators
seeking to apply the new rule. The terms and conditions, which include
meeting current 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 maintenance requirements for these pipelines.
    With special permits, PHMSA individually examined the design,
construction, and operation and maintenance plans for a particular
pipeline before allowing operation at a higher pressure than currently
authorized. In each case, PHMSA conditioned approval based on
compliance with a series of rigorous design, construction, operation,
and maintenance standards. PHMSA's experience with these requests for
special permits leads 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 proposed rule
would set rigorous safety standards. In place of individual
examination, the proposed rule would require 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 would have to certify that a pipeline is
built according to rigorous design and construction standards and agree
to operate under stringent operation and maintenance standards. After
PHMSA receives an operator's certification indicating its intention to
operate at a higher stress level, PHMSA could then follow up with the
operator to verify compliance. As with the special permits, this
proposed 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 segment.
    Several types of segments will not qualify under the proposed rule.
These include the following:
     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.
     Segments of grandfathered pipeline already operating at a
higher stress level but not constructed in accordance with modern
standards. Although grandfathered pipeline has operated successfully at
the higher stress level, PHMSA would examine any further increases
individually through the special permit process.
     Bare pipe. This pipe lacks the coating needed to prevent
corrosion and to make cathodic protection effective.
     Pipe with wrinkle bends. Section 192.315(a) currently
prohibits wrinkle bends in pipeline operating at hoop stress exceeding
30 percent of SMYS.
     Pipe experiencing failures indicative of a systemic
problem, such as seam flaws, during the initial hydrostatic testing.
Such pipe is more likely to have inherent defects that can grow to
failure more rapidly at higher stress levels and thus will not qualify.
     Pipe manufactured by certain processes, such as low
frequency electric welding process, will not qualify because it could
not satisfy the requirements of the proposed rule.
     Segments which cannot accommodate internal inspection
devices. These segments would not qualify because the proposed rule
would require internal inspection.
    We are proposing to establish slightly different requirements for
segments that have already been operating and those which are to be
newly built. Some variation is necessary or appropriate with an
existing pipeline. For example, the requirement for cathodically
protecting pipeline within 12 months of construction is an existing
requirement for all pipelines. A proposed requirement for the operator
of an existing 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. Proposing
proof of five percent fewer nondestructive tests done on an existing
segment at the time of construction recognizes the possibility that,
over time, an operator's records might not be complete. The overriding
principal 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 proposed here are too high for existing segments.
Setting the qualification standards lower for existing segments could
encourage operators to construct a pipeline at the lower standards and
seek to raise the operating pressure at some future date.
    Although pipeline proponents have not yet revealed their final
plans, PHMSA anticipates the proposed trans-Alaskan gas pipeline will
require an alternative design approach to address anticipated operating
conditions in the Arctic. This alternative approach will be subject to
PHMSA review. To a large

degree, the technical requirements for operation at a higher stress
level in this proposed rule will guide agency actions in reviewing the
plans for a trans-Alaskan gas pipeline. However, the unique operating
environment of the Arctic will dictate changes. For instance, even
higher strength steels will be needed. PHMSA will have to look closely
at the level of inspection needed to protect the environment and help
ensure the long-term safety of the pipeline.

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

    Table B.4 describes the status of requests for special permits
seeking relief from the current design requirements to allow operation
at higher stress levels. For the most part, this proposed rule
addresses the relief requested. PHMSA has already granted many of these
under terms and conditions that vary slightly from those in this
proposed rule. In some cases, the relief granted extends beyond the
issues addressed in this proposed rule. It may be appropriate for PHMSA
to review the special permits already granted after completion of the
rulemaking to determine the need for changes. We seek comment on this
issue.
    PHMSA is also considering how to handle the pending requests and
whether to consider others during the course of rulemaking. One option
is to continue evaluating each request in light of the terms and
conditions proposed here. Any grants of special permits during the
course of rulemaking could be limited in time with the intention of
revisiting the need for a special permit after completing the
rulemaking. Another option is to defer further action on pending
requests at least until PHMSA completes the rulemaking.
    In any case, issuance of a final rule will not foreclose future
requests for relief through the special permit process. We can
anticipate, for instance, that operators may seek special permits
covering pipeline that does not meet fully some of the terms and
conditions in a final rule. In such a case, the operator may be able to
demonstrate the existence of other safety measures that address the
unmet terms and conditions. Notwithstanding the final rule, the
operator would be able to request a special permit which PHMSA would
consider under the usual public process for special permits.

B.7. Statutory Considerations

    Under 49 U.S.C. 60102(a), PHMSA has broad authority to issue safety
standards for the design, construction, operation, and maintenance of
gas transmission pipelines. Under 49 U.S.C. 60104(b), PHMSA may not
require an operator to modify or replace existing pipeline to meet a
new design or construction standard. Although this proposal includes
design and construction standards, these standards simply add more
rigorous, non-mandatory requirements. This proposal does not require an
operator to modify or replace existing pipeline 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 proposal would allow 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 operation and maintenance 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 proposed 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 Technical Pipeline Safety
Standards Committee (Committee). Both the public and the Committee have
already reviewed the concepts underlying this proposal. As discussed
above, PHMSA opened this docket and conducted a public meeting in 2006
to discuss the potential for increasing MAOP. PHMSA subsequently
briefed the Committee. Finally, PHMSA has sought public comment on
several requests for special permits to allow operation at increased
MAOP. PHMSA considered the Committee discussion and public comment in
developing this proposed rule. This notice of proposed rulemaking seeks
public comment on the proposed rule; the Committee will formally
consider it in a future meeting. PHMSA will address the public comments
and the Committee's recommendations in preparing final action.

C. The Proposed Rule

C.1. In General

    The proposed rule would add a new section (Sec.  192.620) to
Subpart L--Operations. This new section would explain 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 proposed 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) to be located in Subpart C--Pipe
Design and Subpart G--General Construction Requirements for
Transmission Lines and Mains, respectively. In addition, the proposed
rule would make necessary conforming changes to existing sections on
incorporation by reference (Sec.  192.7) and maximum allowable
operating pressure (Sec.  192.619).

C.2. Proposed Amendment to Sec.  192.7--Incorporation by Reference

    The proposed rule would add 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 proposed new Sec.  192.112.

C.3. Proposed New Sec.  192.112--Additional Design Requirements

    The proposed rule would add a new section to Subpart C--Pipe Design
in 49 CFR Part 192. The new section, Sec.  192.112 would prescribe
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 would prevent flaws leading to pipe failure. Unlike other
design standards, Sec.  192.112 would apply to a new or existing
pipeline only to the extent that an operator elects to operate at a
higher

MAOP than allowed in current regulations.
    Proposed paragraph (a) sets high manufacturing standards for the
steel plate or coil used for the pipe. These include reducing oxygen
content to produce more uniform chemistry in the plate and limiting the
use of alloys in place of carbon. The pipe would be manufactured in
accordance with level 2 of API Specification 5L, with the wall
thickness and 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 discussed
elsewhere in this notice of proposed rulemaking also help prevent
denting and ovality.
    Proposed paragraph (b) addresses fracture control of the metal.
First the metal would have to be tough; that is, deform plastically
before fracturing. To the extent that the accepted industry toughness
standard does not explicitly address the particular pipe used and
expected operating conditions, correction factors would have to be
used. 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.
    Proposed paragraph (c) provides tests to verify that there are no
deleterious imperfections in the plate or coil. The macro-etch test
will identify flaws that impact the surface of the plate or coil.
Interior flaws will show up in ultrasonic testing.
    In addition to the quality of the steel, the integrity of a pipe
depends on the integrity of the seams. Proposed paragraph (d) provides
for a quality assurance program to assure tensile strength and
toughness of the seams so that they resist breaking under regular
operations. Hardness and ultrasonic tests would ensure that the seams
also resist puncture damage.
    Proposed paragraph (e) would require a longer mill test pressure
for new pipe at a higher hoop stress than required by current
regulations. The mill test is used to discover flaws introduced in
manufacture. 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.
    Proposed paragraph (f) would set rigorous standards for factory
coating designed to protect the pipe from external corrosion. A quality
assurance program would address all aspects of the application of
coating that will protect the pipe. This would include applying a
coating resistant to damage during installation of the pipe and
examining the coated pipe to determine whether the applied coating is
uniform and without gaps. Thin spots or holes in the coating make it
more likely for corrosion to occur and more difficult to protect the
pipe cathodically.
    Proposed paragraph (g) would require that factory-made fittings,
induction bends, and flanges be certified as to their serviceability.
In addition, the amount of non-carbon added in the steel for these
fittings and flanges would be limited.
    Proposed paragraph (h) would require compressor design to limit the
temperature of discharge 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 must be of sufficient length and rigor to detect coating
integrity issues.

C.4. Proposed New Sec.  192.328--Additional Construction Requirements

    The proposed rule would also add a new section to Subpart G--
General Construction Requirements for Transmission Lines and Mains. The
new section, Sec.  192.328, would prescribe additional construction
requirements, including rigorous quality control and inspections, as
conditions for operation of the steel pipeline at higher stress levels.
These include requirements for rigorous quality control and inspection
during construction. 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 MAOP than allowed in current
regulations.
    Proposed paragraph (a) would require a quality assurance plan for
construction. Quality assurance, also called quality control, is common
in modern pipeline construction. Activities such as lowering the pipe
into the ditch and backfilling, if poorly done, can damage the pipe.
Other construction activities such as nondestructive examination, if
poorly done, will result in flaws remaining in the pipeline. Using a
quality assurance 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 quality assurance 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, proposed paragraph (a) would require quality
assurance plans to contain specific performance measures for field
coating. Field coating would have to meet substantially the same
standards as coating applied at the mill and the individuals applying
the coating would have to be appropriately trained and qualified.
    Proposed paragraph (b) would require non-destructive testing of all
girth welds. Although past industry practice 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 detect flaws in
girth welds. 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. To account for this, proposed paragraph (b) would require
testing records for only 95 percent of girth welds on existing
segments.
    Proposed paragraph (c) would require 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.
    Proposed 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 relatively close to failure during
operation. This could leave in place smaller flaws that could grow more
rapidly at higher stress level. To prevent this from occurring, the
proposed paragraph would disqualify any segment which experiences a
failure during the initial strength test indicative of systemic flaws
in the material.
    Proposed paragraph (e) addresses cathodic protection on an existing
segment. Applying this requirement to new segments is unnecessary since
current regulations already require cathodic protection within 12
months of construction. Proposed paragraph (e) would prevent an
existing segment not cathodically protected within 12 months after
construction from qualifying for operation at a higher stress level
under this proposed regulation.

    Proposed paragraph (f) addresses electrical interference for new
segments. During construction, it is relatively easy to identify
sources of electrical interference which can impair future cathodic
protection. Addressing interference at this time supports better
corrosion control. The proposed additional operation and maintenance
requirements of proposed Sec.  192.620(d)(6) require operators electing
operation at higher stress levels to address electrical interference on
existing pipelines prior to raising the MAOP.

C. 5. Proposed Amendment to Sec.  192.619--Maximum Allowable Operating
Pressure

    The proposed rule would amend existing Sec.  192.619 by adding a
new paragraph (d) Proposed Sec.  192.619(d) would provide an additional
means to determine the MAOP for certain steel pipelines. In addition,
the proposed rule would make conforming changes to existing paragraph
(a) of the section.

C.6. Proposed New Sec.  192.620--Operation at an Alternative MAOP

    The proposed rule would add a new section, Sec.  192.620, to
subpart L of part 192, to specify what an operator would have to do in
order to elect an alternative MAOP based on higher stress levels. The
proposed rule would apply to both new and existing pipelines.
C.6.1. Calculating the Alternative MAOP
Proposed Sec.  192.620(a)
    Proposed paragraph (a) describes how to calculate the alternative
MAOP based on the higher stress levels. Qualifying segments of pipe
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 would be made in the design factors used for segments
within compressor or meter stations or segments underlying certain
crossings.
C.6.2. Which Pipeline Qualifies
Proposed Sec.  192.620(b)
    Proposed paragraph (b) describes which segments of new or existing
pipeline are qualified for operation at the alternative MAOP. The
alternative MAOP would be 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 would qualify.
Mechanical couplings in lieu of welding would not be 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.
C.6.3. How an Operator Selects Operation Under This Section
Proposed Sec. Sec.  192.620(c)(1) and (2)
    Proposed paragraphs (c)(1) and (2) would require an operator to
notify PHMSA when it elects to establish the MAOP under this section.
An operator notifies PHMSA of the election by submitting a
certification by a senior executive that the pipeline meets the
rigorous additional design and construction regulations of this
proposed rule. A senior executive must also certify that the operator
has changed its operation and maintenance procedures to include the
more rigorous additional operation and maintenance requirements of the
proposed rule. In addition, a senior executive must certify that the
operator has reviewed its damage prevention program in light of
industry consensus standards and practices and made any needed changes
to it to ensure that the program meets or exceeds those standards or
practices. An operator would have to submit the certification at least
180 days prior to commencing operations at the MAOP established under
this section. This will provide PHMSA 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.
C.6.4. Initial Strength Testing
Proposed Sec.  192.620(c)(3)
    Proposed paragraph (c)(3) addresses initial strength testing
requirements. In order to establish the MAOP under this section, an
operator would have to perform the initial strength testing of a new
segment at a pressure at least as great as 125 percent of the MAOP.
Since an existing pipeline was previously operated at a lower MAOP, it
may have been initially tested at a pressure less than 125 percent of
the higher MAOP allowed under this section. If so, paragraph (c) would
allow the operator to elect to conduct a new strength test in order to
raise the MAOP.
C.6.5. Operation and Maintenance
Proposed Sec.  192.620(c)(4)
    Proposed paragraph (c)(4) would require an operator to comply with
the additional operating and maintenance requirements of paragraph (d).
Compliance with these additional requirements is required if an
operator elects to calculate the MAOP for a segment under paragraph (a)
and notifies PHMSA of that election under paragraph (c)(1) of this
section.
C.6.6. New Construction and Maintenance Tasks
Proposed Sec.  192.620(c)(5)
    Proposed paragraph (c)(5) 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 operation and
maintenance activities are qualified. During a 2005 review of the
qualifications program, PHMSA discussed the need to ensure that
construction-related activities are properly done:

    We also have anecdotal information about errors in construction
and the problems they cause. One incident [in late 2006] caused
serious concern within PHMSA. The incident involved a dig-in by the
pipeline company during construction near a large school. If the
released gas had ignited, it could have resulted in a catastrophe
exceeding the one that led to enactment of the Natural Gas Pipeline
Safety Act of 1968. Although the construction project was not new
construction, the distinctions between new construction and
maintenance are often blurred, and excavation of the right-of-way of
an active pipeline for any form of construction requires careful
safety oversight. Federal and State inspectors can point to numerous
situations in which they found dents or coating damage probably
caused by poor backfill, pipeline handling, or equipment damage
likely occurring during construction. When these problems become
evident after the line has been in operation many years, it is too
late for either remediation or enforcement action. Occasionally we
have been able to address problems discovered soon after
construction. As an example, a multi-agency investigation into
construction of a natural gas transmission line in the mid-1990s
uncovered numerous violations of pipeline safety and other
environmental laws. Our enforcement order directed the operator to
undertake a program to remediate the problems associated with
numerous instances of improper backfill.
    Finally, we analyzed the pipeline incident data. In the first
analysis, we reviewed the incidents from 1984 through 2005 where the
operator had noted construction as either the primary or a secondary
causal factor. Although the number of incidents is small, we observe
a trend line increasing for both gas transmission and hazardous
liquid pipelines. This is contrary to the general trend in pipeline
incidents. We next looked at incidents in which we suspect
construction issues were involved, incidents occurring within two
years of construction of the pipeline. We eliminated those incidents
clearly not caused by construction error, such

as excavation damage occurring during operation of the line. When we
add these suspected construction-related incidents to those clearly
involving construction error, the trend line, for both gas
transmission and hazardous liquid pipelines, is sloped more steeply
upward.

    FDMS Docket ID PHMSA-RSPA-2004-19857-56, p. 2. Proposed paragraph
(c)(5) would require operators seeking to operate at the higher stress
levels allowed under this section to take steps designed to reduce
incidents caused by errors during new construction and maintenance
activities. As part of the 2005 review of the qualifications program,
PHMSA sought comment on a broad approach to ensuring that construction-
related activities are done properly. Proposed paragraph (c)(5) would
incorporate this approach. The approach would allow an operator to
select an appropriate way to verify the proper performance of a
construction-related activity. For example, non-destructive testing of
all girth welds will significantly reduce the risk of a future weld
failure. An operator could also effectively use quality controls during
construction or qualify the individuals performing the tasks. Both
industry consensus standards, and subpart N, provide models for
qualifying individuals performing safety tasks.
C.6.7. Recordkeeping
Proposed Sec.  192.620(c)(6)
    Proposed paragraph (c)(6) clarifies 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. However, because the additional requirements proposed in this
section address requirements found in other subparts of part 192, the
recordkeeping requirements may cause confusion. For example, proposed
Sec.  192.620(d)(9) would require a baseline assessment for integrity
for a segment operated at the higher stress level regardless of its
potential impact on a high consequence area. Section 192.947 requires
operators to maintain records of baseline assessments for the useful
life of the pipeline. However, proposed new Sec.  192.620 would be in
subpart L. Section 192.709 requires an operator to retain records for
an inspection done under subpart L for a more limited time.
Accordingly, this paragraph would clarify the need to maintain all
records demonstrating compliance for the useful life of the pipeline.

C.7. Additional Operation and Maintenance Requirements

Proposed Sec.  192.620(d)
    Paragraph (d) sets forth 11 operating and maintenance requirements
that supplement the existing requirements in part 192. Current Sec.
192.605 requires an operator to develop operation and maintenance
procedures to implement the requirements of subpart L and M. Since
proposed Sec.  192.620(d) is in subpart L, an operator would have to
develop and follow the operation and maintenance 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. These are discussed in more detail below.
C.7.1. Threat Assessments
Proposed Sec.  192.620(d)(1)
    Proposed paragraph (d)(1) would require preparation of a threat
assessment consistent with that done under integrity management to
address the risks of operating at an increased stress level. This
proposed requirement is not limited to high consequence areas, but
applies to the entire segment operating at the increased stress level.
    This proposed requirement comes from our experience with integrity
management and special permits. Under integrity management, operators
develop a detailed threat matrix identifying the risks associated with
operating their pipelines. These risks include both general risks faced
by all pipelines and those risks specific to the particular pipeline
and its environment. The matrix lists specific threats and the
mitigative measures an operator is using to address each threat. As
applied to the special permits, and in this proposed rule, this threat
assessment ensures that an operator takes into account any additional
risk operation at a higher stress level imposes.
C.7.2. Public Awareness
Proposed Sec.  192.620(d)(2)
    Proposed paragraph (d)(2) would require 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 high consequence areas, the potential impact circle
recalculated to reflect operation at a higher stress level. This is
intended to get necessary information for safety to the people
potentially impacted by a failure.
C.7.3. Emergency Response
Proposed Sec.  192.620(d)(3)
    Proposed paragraph (d)(3) addresses the additional needs for
responding to emergencies for operation at higher stress levels.
Consistent with the conditions imposed in the special permits, and past
experience with response issues, the paragraph would require methods
such as remote control valves to provide more rapid shut-down in the
event of an emergency.
C.7.4. Damage Prevention
Proposed Sec.  192.620(d)(4)
    Proposed 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 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 stress levels. This paragraph proposes to add several new or
more specific measures to existing requirements designed to prevent
damage to pipelines from outside force. Additional attention to this
area is important since the trend line for incidents caused by outside
force on gas transmission pipelines between 2002 and 2006 is
increasing.
    The first more specific measure, in proposed 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 proposed requirement would be for

patrols on the same frequency as for hazardous liquid pipelines (i.e.,
a minimum of 26 times a year). This is slightly more frequent than
included in the special permits, but PHMSA believes that it is
appropriate for a rule of general applicability.
    The increased patrols that would be required by this rulemaking,
however, represent the majority of the incremental costs imposed by
this rule. Therefore, PHMSA specifically requests comment on whether
the number of patrols required optimally balances the potential risk
reduction and increase in burden. We seek information on:
     Would patrolling less frequently such as four times per
year (similar to requirements at highway and railroad crossings)
provide a cost-effective alternative?
     How often are pipelines that currently operate at 80% of
SMYS patrolled? How effective are these patrols in providing accurate
and timely information about potential sources of ground disturbance
and other outside force damage?
     How could operators incorporate patrolling in their risk
management plan if PHMSA did not mandate a fixed frequency?
    Other more specific or new measures to address damage prevention
include developing and implementing a plan to monitor and address
ground movement, a proposed requirement of paragraph (d)(4)(ii). Ground
movement such as earthquakes, landslides, and nearby demolition or
tunneling can damage pipe. Since pipelines near the surface are more
likely to be damaged by surface activities, proposed paragraph
(d)(4)(iii) would require an operator to maintain the depth of cover
over a pipeline. Line-of-sight markers alert excavators, emergency
responders, and the general public of the presence and general location
of pipelines. Proposed paragraph (d)(4)(iv) would require these markers
to improve both damage prevention and enhance public awareness.
    Damage prevention programs are improving because of the work being
done by the Common Ground Alliance, a national, non-profit educational
organization dedicated to preventing damage to pipelines and other
underground utilities. The Common Ground Alliance has compiled best
practices applicable to all parties relevant to preventing damage to
underground utilities and actively promotes their use. Proposed
paragraph (d)(4)(v) would require operators electing to operate at
higher stress levels to evaluate their damage prevention programs in
light of industry consensus standards and practices. An operator would
have to identify the standards or practices used and make appropriate
changes to the damage prevention program. The resulting program would
have to meet or exceed the identified standards or practices. This
approach is consistent with annual reviews of operation and maintenance
programs under Sec.  192.605. An operator would have to include in the
certification required under proposed Sec.  192.620(c)(1) that the
review and upgrade has occurred.
    Proposed paragraph (d)(4) would also require one measure not
included as a condition in the special permits, namely 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 would include 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 operator qualification regulations into excavation
activities and providing that excavation is included as a covered task
under operator qualification 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-06-03; 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 Common
Ground Alliance. This proposed paragraph would require 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 plan would require the operator to
integrate activities under those programs to provide better protection
for the right-of-way of pipeline operated at higher stress level.
C.7.5. Internal Corrosion Control
Proposed Sec.  192.620(d)(5)
    Proposed paragraph (d)(5) would add 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 would have to include mandated use of filter
separators, gas quality monitoring equipment, cleaning pigs, and
inhibitors. Maximum levels of contaminants that could promote corrosion
are set to be monitored quarterly. PHMSA believes the levels are fully
consistent with the requirements in Federal Energy Regulatory
Commission tariffs designed to prevent internal corrosion.
C.7.6. External Corrosion Control
Proposed Sec. Sec.  192.620(d)(6), (7), and (8)
    Since external corrosion is one of the greatest risks to the
integrity of pipelines operating at higher stress levels, the special
permits and this proposed rule contain several measures to prevent it
from occurring. These include use of effective coating, addressing
interference, early installation of cathodic protection, confirming the
adequacy of coating and cathodic protection and diligent monitoring of
cathodic protection levels. The quality of the coating and installation
of cathodic protection are addressed in proposed sections on design and
construction. 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. Proposed paragraph (d)(6) would require an operator
to identify and address interference early before damage to the pipe
can occur.
    Proposed paragraph (d)(7) would require 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 stress
levels. This is accomplished through indirect assessment, such as a
close interval survey. After completion of the baseline internal
inspection required by proposed Sec.  192.620(d)(9), an operator would
have to integrate the results of that inspection with the indirect
assessments. An operator would have to

also take remedial action to correct any inadequacies. In high
consequence areas, an operator would have to periodically repeat
indirect assessment to confirm that the cathodic protection system
remains as functional as when first installed.
    Proposed paragraph (d)(8) would require 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, must 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 would have to confirm, through a
close interval survey, that adequate cathodic protection levels were
restored.
C.7.7 Integrity Assessments
Proposed Sec. Sec.  192.620(d)(9) and (10)
    Among the most important ways of ensuring integrity during pipeline
operations are the assessments done under the integrity management
program requirements in subpart O. Proposed paragraphs (d)(9) and
(d)(10) would require operators electing to operate at higher stress
levels to perform both baseline and periodic assessments of the entire
segment operating at the higher stress level, regardless of whether the
segment is located in a high consequence area. The operator would have
to use both a geometry tool and a high resolution magnetic flux tool
for the entire 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 direct
assessment. The operator would then integrate the information provided
by these assessments with testing done under previously described
paragraphs. This analysis would form the basis for mitigating measures
described in the operator's threat assessment, and prompt repairs under
proposed paragraph (d)(11).
C.7.8. Repair Criteria
Proposed Sec.  192.620(d)(11)
    The repair criteria under proposed paragraph (d)(11) for anomalies
in a segment operating at a higher stress level are slightly more
conservative than for other pipeline, including pipeline covered by a
integrity management program. With the tougher pipe, better coating and
seams, and careful attention to damage prevention and corrosion
protection, a pipeline operated at higher stress levels should
experience few anomalies needing evaluation. The higher stress levels
of operation can allow more rapid growth of anomalies. Therefore, more
conservative repair criteria are needed.

C.8. Overpressure Protection

Proposed Sec.  192.620(e)
    The alternative MAOP is higher than the upper limit of the required
overpressure protection under existing regulations. Proposed paragraph
(e) would increase the overpressure protection limit to 104 percent of
the MAOP, which is 83 percent of SMYS, for a segment operating at the
alternative MAOP.

D. Regulatory Analyses and Notices

D.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).

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

    Due to billions of dollars in benefits, the Department of
Transportation (DOT) considers this proposed 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 proposed rulemaking is
also significant under DOT regulatory policies and procedures (44 FR
11034; Feb. 26, 1979).
    PHMSA prepared a draft Regulatory Evaluation of the proposed rule.
A copy is in Docket ID PHMSA-2005-23447. If you have comments about the
Regulatory Evaluation, please file them as described under the
ADDRESSES heading of this document.
    PHMSA estimates that the proposed 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 proposed rule will result in an annual additional 700
miles of new pipeline whose operators elect to use an alternative MAOP.
    PHMSA expects the benefits of the proposed rule to be substantial
and greatly 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
proposed rule that industry and PHMSA technical staff have identified.
The expected benefits of the proposed rule that cannot be readily
quantified include:
     Reductions in incident consequences
     Increases in pipeline capacity
     Increases in the amount of natural gas filling the line,
commonly called line pack
     Reductions in capital expenditures on compressors for new
pipelines
     Reductions in adverse environmental impacts
    In the case of new pipelines, the ability to use an alternative
MAOP will make it possible to transport more product. Quantifying the
value of this increased capacity is difficult, and no estimate has been
developed for this analysis. Nonetheless, PHMSA expects the value of
increased capacity due to use of alternative MAOP by gas pipelines to
be significant. Estimates made with respect to the proposed trans-
Alaskan gas pipeline include an estimated increase of 14.2 million
standard cubic feet of gas per day. 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 enormous benefits
which are difficult to quantify. The reduced amount of exterior storage
capacity resulting from increased line pack may result in capital or
operation and maintenance savings for the pipelines or their customers.
Increased line pack increases the ability to continue gas delivery
during short outages such as maintenance and to increase the amount of
gas quickly during peak periods. These benefits are not readily
quantifiable.
    The quantified benefits consist of
     Fuel cost savings
     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 proposed rule, they
exceed $100 million per year.
    As a consequence of the proposed rule, PHMSA estimates that
pipeline operators will realize annually recurring benefits due to fuel
cost savings of $58.8 million that begin in the initial year after the
rule goes into effect and $9.8 million that begin in each subsequent
year. 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, the one-time benefits resulting from this
added mileage will be the same each year.) The benefits of the proposed
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
                              Proposed Rule
------------------------------------------------------------------------
                                                        Estimate of new
                                   Estimate for year  benefits occurring
             Benefit                1  (millions of   in each subsequent
                                   dollars per year)  year  (millions of
                                                       dollars per year)
------------------------------------------------------------------------
Reduced incident consequences...  Not quantified....  Not quantified.
Fuel cost savings...............  $49.0 (recurring).  $0.0 (recurring).
Reduced capital expenditures....  $54.6 (non-         $54.6 (non-
                                   recurring).         recurring).
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.......................  $49.0 recurring +   $54.6 non-
                                   $54.6 non-          recurring.
                                   recurring.
------------------------------------------------------------------------

    The present value of the benefits evaluated over 20 years at a
three percent discount rate would be $1,541 million, while the present
value of the benefits over 20 years at a seven percent discount rate
would be $1,098 million. For both discount rates, the annualized
benefits would be $103.6 million.
    PHMSA expects the costs attributable to the proposed rule are most
likely to be incurred by operators for
     Performing baseline internal inspections
     Performing additional internal inspections
     Performing anomaly repairs
     Installing remotely controlled valves on either side of
high consequence areas
     Preparing threat assessments
     Patrolling pipeline rights-of-way
     Preparing the paperwork notifying PHMSA of the decision to
use an alternative MAOP
    Overall, the costs of the proposed 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 Proposed 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......................  $10,080...........  $11,760 to $25,200  $26,880...........  $28,560 to
                                                                                $42,000.
Notifying PHMSA.................  Nominal...........  Nominal...........  Nominal...........  Nominal.
                                 -------------------------------------------------------------------------------
    Total.......................  $43,922...........  $618 each year      $46,187...........  $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 would be $435 million, while the present value of
the costs over 20 years at a seven percent discount rate would be $293
million. The annualized costs at the 3% discount rate would be $29
million, while the annualized costs at the 7% discount rate would be
$28 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 ($435 million at three percent and $293
million at seven percent), the proposed rule is expected to be cost-
beneficial.

D.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 proposed rule would affect 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 the proposed 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% 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 proposed rule will have $6.5 million or

less in annual revenue. PHMSA does not expect that any local gas
distribution companies or gathering systems will be taking advantage of
the potential to use an alternative MAOP.
    The proposed 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 proposed rule will not have a substantial economic impact on
a substantial number of small entities.
    PHMSA invites public comment on impacts this proposed rule would
have on small entities.

D.4. Executive Order 13175

    PHMSA has analyzed this proposed rulemaking according to Executive
Order 13175, ``Consultation and Coordination with Indian Tribal
Governments.'' Because the proposed rulemaking would 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.

D.5. Paperwork Reduction Act

    This proposed rule adds notification and threat assessment
paperwork requirements on pipeline operators voluntarily choosing an
alternative MAOP for their pipelines. Based on analysis of the
regulation, there will be an estimated 2,712 total annual burden hours
attributable to the notification and threat assessment requirements in
the first year. In following years, the annual burden is expected to
decrease to 452 hours. The associated cost of these annual burden hours
is $180,289 in year one, and $30,048 thereafter. No other burden hours
and associated costs are expected. See the Paperwork Reduction Act
analysis in the docket for a more detailed explanation. PHMSA seeks
comments on these projections.

D.6. Unfunded Mandates Reform Act of 1995

    This proposed rule does not impose unfunded mandates under the
Unfunded Mandates Reform Act of 1995. It does not result in costs of
$100 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
proposed rulemaking.

D.7. National Environmental Policy Act

    PHMSA has analyzed the proposed rulemaking for purposes of the
National Environmental Policy Act (42 U.S.C. 4321 et seq.). The
proposed rulemaking would require limited physical change or other work
that would disturb pipeline rights-of-way. In addition, the proposed
rulemaking would codify 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. PHMSA has preliminarily determined the proposed
rulemaking is unlikely to significantly affect the quality of the human
environment. An environmental assessment document is available for
review in the docket. PHMSA will make a final determination on
environmental impact after reviewing the comments to this proposal.

D.8. Executive Order 13132

    PHMSA has analyzed the proposed 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 proposed
rule does not have a substantial direct effect on the States, the
relationship between the national government and the States, or the
distribution of power and responsibilities among the various levels of
government. The proposed 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.
The same law provides that Federal regulation would not preempt state
law for intrastate pipelines. 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
proposed rule, that govern preemption of State law. Therefore, the
consultation and funding requirements of Executive Order 13132 do not
apply.

D.9. Executive Order 13211

    This proposed 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 proposed 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 proposed
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.

    For the reasons provided in the preamble, PHMSA proposes to amend
49 CFR part 192 as follows:

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

    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.

    2. In Sec.  192.7, in paragraph (c)(2) amend the table of
referenced material by 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  Incorporation by reference.

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

------------------------------------------------------------------------
   Source and name of referenced
             material                         49 CFR reference
------------------------------------------------------------------------

                              * * * * * * *
C.* * *                             ....................................
(6) ASTM Designation: A 578/A578M-- Sec.   192.112(c)(2)(ii)
 96 (Re-approved 2001) ``Standard
 Specification for Straight-Beam
 Ultrasonic Examination of Plain
 and Clad Steel Plates for Special
 Applications.

                              * * * * * * *
------------------------------------------------------------------------

    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 calculated
under Sec.  192.620, a segment must meet the following additional
design requirements:

------------------------------------------------------------------------
                                  The pipeline segment must meet this
To address this design issue:           additional requirement:
------------------------------------------------------------------------
(a) General standards for the  (1) The plate or coil used for the pipe
 steel 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 0.23
                                percent by weight, as calculated by the
                                Ito-Bessyo formula (Pcm formula), for
                                wall thickness of one inch (25 mm) or
                                less, and 0.25 percent for wall
                                thickness greater than one inch (25 mm).
                               (3) The ratio of the specified outside
                                diameter of the pipe to the specified
                                wall thickness must be less than 100.
                                The wall thickness 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
                                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); and
                                  (ii) Any correction factors needed to
                                   address pipe grades, pressures,
                                   temperatures, or gas compositions not
                                   expressly addressed in API
                                   Specification 5L, product
                                   specification level 2 (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 and gas compositions the
                                   pipeline is expected to experience;
                                  (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.
                               (3) If it is not physically possible to
                                achieve the pipeline toughness
                                properties of paragraphs (b)(1) and (2)
                                of this section, mechanical crack
                                arrestors 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         (1) There must be a comprehensive mill
 control.                       inspection program to check for defects
                                and inclusions affecting pipe quality.
                               (2) This mill inspection program must
                                include:
                                  (i) 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 at
                                   least 2 on the Mannesmann scale or
                                   equivalent; and
                                  (ii) An ultrasonic test of the ends
                                   and at least 50 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
                                   pipeline designed after [the
                                   effective date of the final rule],
                                   the test must be done in accordance
                                   with Level B of ASTM A 578/A578M
                                   (incorporated by reference, see Sec.
                                    192.7) or equivalent.
(d) Seam quality control.....  (1) There must be a quality assurance
                                program for pipe seam welds:
                                  (i) To assure tensile strength
                                   provided in API Specification 5L
                                   (incorporated by reference, see Sec.
                                    192.7) for appropriate grades; and
                                  (ii) To assure toughness of at least
                                   35 foot-pounds at 32 degrees
                                   Fahrenheit (or minimum operating
                                   temperature).
                               (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 hydrostatic testing.
(e) Mill hydrostatic test....  (1) All pipe to be used in a new segment
                                must be hydrostatically tested at the
                                mill at a test pressure corresponding to
                                a hoop stress of 95 percent SMYS for 20
                                seconds, including the allowance for end
                                loading stresses.
                               (2) Pipe previously in operation 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 non-shielding,
                                fusion bonded epoxy coating.
                               (2) Coating on pipe used for trenchless
                                installation must 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.
                               (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.
(h) Compressor stations......  (1) A compressor station must be designed
                                to limit discharge temperature to a
                                maximum of 120 degrees Fahrenheit (49
                                degrees Centigrade) or the higher
                                temperature allowed in paragraph (h)(2)
                                of this section.
                               (2) If testing shows that the coating
                                will withstand a higher temperature in
                                long-term operations, the compressor
                                station may be designed to limit
                                discharge temperature to that higher
                                temperature.
------------------------------------------------------------------------

    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:

------------------------------------------------------------------------
 To address this construction     The pipeline segment must meet this
            issue:                additional construction requirement:
------------------------------------------------------------------------
(a) Quality assurance........  (1) The construction of the 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.
(b) Girth welds..............  (1) All girth welds on a new segment must
                                be non-destructively examined in
                                accordance with Sec.   192.243(b) and
                                (c).
                               (2) At least 95 percent of girth welds on
                                a segment that was constructed prior to
                                the effective date of this rule must
                                have been 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.
                               (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 segment must not experience any
                                failures indicative of fault in material
                                during strength testing, including
                                initial hydrostatic testing.
(e) Cathodic protection......  (1) If the segment has been in operation,
                                the cathodic protection system on the
                                segment must have been operational
                                within 12 months of construction.
(f) Interference currents....  (1) For a new 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.
------------------------------------------------------------------------

    5. 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 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).
    6. 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 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:

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

    (2) The maximum allowable operating pressure is the lower of the
following:
    (i) The design pressure of the weakest element in the segment,
determined under subparts C and D of this part.
    (ii) The pressure obtained by dividing the pressure to which the
segment was tested after construction by a factor determined in the
following table:

------------------------------------------------------------------------
              Class location                           Factor
------------------------------------------------------------------------
1.........................................  1.25
2.........................................  1.50
3.........................................  1.50
------------------------------------------------------------------------

    (b) When may an operator use the alternative maximum allowable
operating pressure calculated under paragraph (a) of this section? An
operator may use a maximum allowable operating pressure calculated
under paragraph (a) of this section if the following conditions are
met:
    (1) The segment is in a Class 1, 2, or 3 location;
    (2) The 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 segment;
    (4) The segment meets the additional construction requirements
described in Sec.  192.328;
    (5) The segment does not contain any mechanical couplings used in
place of girth welds; and
    (6) If a segment has been previously operated, the segment has not
experienced any failure during normal operations indicative of a fault
in material.
    (c) What is an operator electing to use the alternative maximum
allowable operating pressure required to do? If an operator elects to
use the maximum allowable operating pressure calculated under paragraph
(a) of this section for a segment, the operator must do each of the
following:
    (1) Certify, by signature of a senior executive officer of the
company, as follows:
    (A) The segment meets the conditions described in subsection (b) of
this section; and
    (B) The operating and maintenance procedures include the additional
operating and maintenance requirements of subsection (d) of this
section; and
    (C) The review and any needed program upgrade of the damage
prevention program required by subsection (d)(4)(v) of this section has
been completed.
    (2) Notify PHMSA of its election with respect to a segment at least
180 days before operating at the alternative maximum allowable
operating pressure by sending the certification to the Information
Resources Manager as provided for reports under Sec.  192.951.
    (3) For each segment, do one of the following:
    (i) Perform a strength test as described in Sec.  192.505 at a test
pressure of at least 125 percent of the maximum allowable operating
pressure calculated under paragraph (a) of this section; or
    (ii) For a segment in existence prior to the effective date of this
regulation, certify, under paragraph (c)(1) of this section, that the
strength test performed under Sec.  192.505 was conducted at a test
pressure of at least 125 percent of the maximum allowable operating
pressure calculated under paragraph (a) of this section.
    (4) Comply with the additional operation and maintenance
requirements described in paragraph (d) of this section.
    (5) If the performance of a construction task affects the integrity
of the segment, ensure that the task is performed properly by doing at
least one of the following:
    (i) Include quality controls during construction addressing
performance of the task;
    (ii) Use an integrity verification method that addresses
performance of the task; or
    (iii) Demonstrate that the individual performing the task has the
knowledge, skills, and ability to do so.
    (6) Maintain, for the useful life of the pipeline, records
demonstrating compliance with paragraphs (b), (c)(5), and (d) of this
section.
    (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 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       Take the following additional step:
     stress levels in the
       following areas:
------------------------------------------------------------------------
(1) Assessing threats........  Develop a threat matrix consistent 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 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,
                                do the following:
                                  (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           (i) Ensure that the identification of
 emergency in an area defined   high consequence areas reflects the
 as a high consequence area     larger potential impact circle
 in Sec.   192.903.             recalculated under paragraph (d)(2)(i)
                                of this section.
                               (ii) If personnel response time to
                                mainline valves on either side of the
                                high consequence area exceeds one hour,
                                provide remote valve control through a
                                supervisory control and data acquisition
                                system, other leak detection system, or
                                an alternative method of control.
                               (iii) Remote valve control must include
                                the ability to open and close the valve,
                                monitor the position of the valve, 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    (i) Patrol the right of way at intervals
 way.                           not exceeding 3 weeks, but at least 26
                                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) Maintain the depth of cover
                                provided for new pipeline under Sec.
                                192.327 or Sec.   192.328(c). 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.
                               (iv) Use line-of-sight line markers
                                satisfying the requirements of Sec.
                                192.707(d) except in agricultural areas,
                                large water crossings 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 standards and
                                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 segment
                                from damage due to excavation
                                activities.
(5) Controlling internal       (i) Develop and implement a program to
 corrosion.                     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 and gas
                                quality monitoring equipment.
                               (iii) Use gas quality monitoring
                                equipment that includes a moisture
                                analyzer, chromatograph, and periodic
                                hydrogen sulfide sampling.
                               (iii) Use cleaning pigs and inhibitors,
                                and sample accumulated liquids.
                               (iv) 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 0.50
                                   grain per hundred cubic feet of gas.
                               (v) Review the program at least quarterly
                                based on the gas stream experienced and
                                implement adjustments to monitor for,
                                and mitigate the presence of,
                                deleterious gas stream constituents.
(6) Controlling interference   (i) Prior to operating an existing
 that can impact external       segment at a maximum allowable operating
 corrosion.                     pressure calculated under this section,
                                or within six months after placing a new