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

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

C.3. Comments on Regulatory Analysis

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

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

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

E. The Final Rule

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

E.1. In General

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    Paragraph (d)(5) adds specificity to the requirements for internal
corrosion control now in pipeline safety standards for pipelines
operated at higher stress levels. These internal corrosion control
programs must include use of gas separators or filter separators and
gas quality monitoring equipment. Operators are required to use
cleaning pigs and inhibitors when corrosive gas is present. (Use of
cleaning pigs and inhibitors is required when the level of one
corrosive contaminant, hydrogen sulfide (H2S), is between
0.5 and 1.0 grain per hundred cubic feet). Most operators who have
applied for special permits to operate their pipeline at alternative
MAOP limit H2S to 0.5 grain. The higher levels allowed in
this rule are within typical FERC tariffs, but may present an increased
likelihood of internal corrosion. Maximum levels of contaminants that
could promote corrosion must be reviewed quarterly, and operators must
adjust their programs as needed to monitor and mitigate any deleterious
gas stream constituents. PHMSA believes the levels are fully consistent
with the requirements in FERC tariffs designed to prevent internal
corrosion.

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

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

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

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

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

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

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

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

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

F. Regulatory Analyses and Notices

F.1. Privacy Act Statement

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

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

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

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

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

    The present value of the benefits evaluated over 20 years at a
three percent discount rate is $1,541 million, while the present value
of the benefits over 20 years at a seven percent discount rate is
$1,098 million. For both discount rates, the annualized benefits would
be $103.6 million.
    PHMSA expects the costs attributable to the rule are most likely to
be incurred by operators for:
     Performing baseline internal inspections.
     Performing additional internal inspections.
     Performing anomaly repairs.
     Installing remotely controlled valves on either side of
HCAs.
     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 rule over 20 years are expected to be as
presented in the following table:

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

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

F.3. Regulatory Flexibility Act

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

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

F.4. Executive Order 13175

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

F.5. Paperwork Reduction Act

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

F.6. Unfunded Mandates Reform Act of 1995

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

F.7. National Environmental Policy Act

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

F.8. Executive Order 13132

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

F.9. Executive Order 13211

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

List of Subjects in 49 CFR Part 192

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

a factor determined in the following table:

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

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

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

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

                                    (A) Conduct periodic close interval
                                     surveys with current interrupted to
                                     confirm voltage drops in
                                     association with periodic
                                     assessments under subpart O of this
                                     part.
                                    (B) Locate pipe-to-soil test
                                     stations at half-mile intervals
                                     within each high consequence area
                                     ensuring at least one station is
                                     within each high consequence area,
                                     if practicable.
                                    (C) Integrate the results with those
                                     of the baseline and periodic
                                     assessments for integrity done
                                     under paragraphs (d)(8) and (d)(9)
                                     of this section.
(8) Controlling external corrosion  (i) If an annual test station
 through cathodic protection.        reading indicates cathodic
                                     protection below the level of
                                     protection required in subpart I of
                                     this part, complete remedial action
                                     within six months of the failed
                                     reading or notify each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service
                                     demonstrating that the integrity of
                                     the pipeline is not compromised if
                                     the repair takes longer than 6
                                     months. An operator must also
                                     notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State; and
                                    (ii) After remedial action to
                                     address a failed reading, confirm
                                     restoration of adequate corrosion
                                     control by a close interval survey
                                     on either side of the affected test
                                     station to the next test station.
                                    (iii) If the pipeline segment has
                                     been in operation, the cathodic
                                     protection system on the pipeline
                                     segment must have been operational
                                     within 12 months of the completion
                                     of construction.
(9) Conducting a baseline           (i) Except as provided in paragraph
 assessment of integrity.            (d)(8)(iii) of this section, for a
                                     new pipeline segment operating at
                                     the new alternative maximum
                                     allowable operating pressure,
                                     perform a baseline internal
                                     inspection of the entire pipeline
                                     segment as follows:
                                    (A) Assess using a geometry tool
                                     after the initial hydrostatic test
                                     and backfill and within six months
                                     after placing the new pipeline
                                     segment in service; and
                                    (B) Assess using a high resolution
                                     magnetic flux tool within three
                                     years after placing the new
                                     pipeline segment in service at the