Document ID: PHMSA-2005-23447-0055
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines
Posted Date: 2008-03-12T04:00Z

[Federal Register: March 12, 2008 (Volume 73, Number 49)]
[Proposed Rules]               
[Page 13167-13185]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12mr08-45]                         

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket ID PHMSA-2005-23447; Notice 2]
RIN 2137-AE25

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

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

ACTION: Notice of proposed rulemaking.

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

[[Page 13168]]

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

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

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

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

FOR FURTHER INFORMATION CONTACT: For information about this rulemaking, 
contact Barbara Betsock by phone at (202) 366-4361, by fax at (202) 
366-4566, or by e-mail at barbara.betsock@dot.gov. For technical 
information, contact Alan Mayberry by phone at (202) 366-5124, or by e-
mail at alan.mayberry@dot.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

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

A. Purpose of the Rulemaking

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

B. Background

B.1. Current Regulations

    The design factor specified in Sec.  192.105 restricts the MAOP of 
a steel gas transmission pipeline based on stress levels and class 
location. For most steel pipelines, the MAOP is defined in Sec.  
192.619 based on design pressure calculated using a formula, found at 
Sec.  192.111, that includes the design factor. In sparsely populated 
Class 1 locations, the design factor specified in Sec.  192.105 
restricts the stress level at which a pipeline can be operated to 72 
percent of the specified minimum yield strength (SMYS) of the steel. 
The operating pressures in more populated Class 2 and Class 3 locations 
are limited to 60 and 50 percent of SMYS, respectively. Paragraph (c) 
of Sec.  192.619 provides an exception to this calculation of MAOP for 
pipelines built before the issuance of the Federal pipeline safety 
standards. A pipeline that is ``grandfathered'' under this section may 
be operated at a stress level exceeding 72 percent of SMYS (but not

[[Page 13169]]

to exceed 80 percent of SMYS) if it was operated at that pressure for 
five years prior to July 1, 1970.
    Part 192 also prescribes safety standards for designing, 
constructing, operating, and maintaining steel pipelines used to 
transport gas. Although these standards have always included several 
requirements for initial and periodic testing and inspection, prior to 
2003, part 192 contained no Federal requirements for internal 
inspection of existing pipelines. Internal inspection is performed 
using a tool known as an ``instrumented pig'' (or ``smart pig''). Many 
pipelines constructed before the advent of this technology cannot 
accommodate an instrumented pig and, accordingly, cannot be inspected 
internally. Beginning in 1994, PHMSA required operators to design new 
pipelines so that they could accommodate instrumented pigs, paving the 
way for internal inspection (59 FR 17281; Apr. 12, 1994).
    In December 2003, PHMSA adopted its gas transmission integrity 
management rule, requiring operators to develop and implement plans to 
extend additional protections, including internal inspection, to 
pipelines located in ``high consequence areas'' (68 FR 69816). 
Integrity management programs, as described in subpart O of part 192, 
include threat assessments, both baseline and periodic internal 
inspection or direct assessment, and additional measures designed to 
prevent and mitigate pipeline failures and their consequences. A high 
consequence area, as defined in Sec.  192.903, is a geographic 
territory in which, by virtue of its population density and proximity 
to a pipeline, a pipeline failure would pose a higher risk to people. 
For purposes of risk analysis, the regulations establish four 
classifications based on population density, ranging from Class 1 
(undeveloped, rural land) through Class 4 (densely populated urban 
areas). In addition to class location, one of the criteria for 
identifying a high consequence area is a potential impact circle 
surrounding a pipeline. The calculation of the circle includes a factor 
for the MAOP, with the result that a higher MAOP results in a larger 
impact circle.

B.2. Evolution in Views on Pressure

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

[[Page 13170]]

all but one type of manufacturing or construction defect that could 
cause failure in the near term. The one type of defect pressure testing 
cannot identify is a flaw in a girth weld. Such defects are detectable 
though pre-operational non-destructive testing, which this proposed 
rule would require.
    The most common defects initiated during operation are caused by 
mechanical damage or corrosion. Improvements in technology have 
resulted in internal inspection techniques that provide operators a 
significant amount of information about defects. Although there is 
significant variance in the capability of the tools used for internal 
inspections, they each provide the operator information about flaws in 
the pipeline that an operator would not otherwise have. An operator can 
then examine these flaws to determine whether they are defects 
requiring repair. In addition, internal inspections with inline 
inspection devices, unlike pressure testing, are not destructive and 
can be done while the pipeline is in operation. Initial internal 
inspection establishes a baseline. Operators can use subsequent 
internal inspections at appropriate intervals to monitor for changes in 
flaws already discovered or to find new flaws requiring repair or 
monitoring. Internal inspections, and other improved life cycle 
management practices, increase the likelihood operators will detect any 
flaws that remain in the pipe after initial inspection and testing, or 
that develop after construction, well before the flaws grow to failure.

B.3. History of PHMSA Consideration

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

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

    A second notice (69 FR 38948; June 29, 2004) announced the 
criteria. The criteria include the use of high quality manufacturing 
and construction processes, effective coating, and a lack of systemic 
problems identified in internal inspections. Although the class 
location waivers do not address increases in stress levels, they do 
address many of the same concerns by looking at how to handle the risks 
caused by operating pressure. Many of the specific criteria, and 
certainly the approach to risk management in the class location 
waivers, helped PHMSA develop the approach to the special permits 
discussed below and, ultimately, to this proposed rule.
    Beginning in 2005, operators began addressing the issue of stress 
level directly with requests that PHMSA allow operation at the MAOP 
levels that the ASME B31.8 Code would allow. With the increasing 
interest, PHMSA held a public meeting on March 21, 2006, to discuss 
whether to allow increased MAOP consistent with the updated ASME 
standards. PHMSA also solicited technical papers on the issue. Papers 
filed in response, as well as the transcript of the public meeting, are 
in the docket for this rulemaking. Later in 2006, PHMSA again sought 
public comment at a meeting of its advisory committee, the Technical 
Pipeline Safety Standards Committee. The transcript and briefing 
materials for the June 28, 2006 meeting are in the docket for the 
advisory committee, Docket ID PHMSA-RSPA-1998-4470-204, 220. This 
docket can be found at http://www.regulations.gov. Comments and papers 
during these efforts overwhelmingly support examining increased MAOP as 
a way to increase energy efficiency and capacity without reducing 
safety.

B.4. Safety Conditions in Special Permits

    In 2005, operators began requesting waivers, now called special 
permits, to allow operation at the MAOP levels that the ASME B31.8 Code 
would allow. In some cases, operators filed these requests at the same 
time they were seeking approval from the Federal Energy Regulatory 
Commission to build new gas transmission pipelines. In other cases, 
operators sought relief from current MAOP limits for existing pipelines 
that had been built to more rigorous design and construction standards.
    In developing an approach to the requests, PHMSA examined the 
operating history of lines already operated at higher stress levels. 
Canadian and British standards have allowed operation at the higher 
stress levels for some time. The Canadian pipeline authority, which has 
allowed higher stress levels since 1973, reports the following 
experience with pipelines operating at stress levels higher than 72 
percent of SMYS:
     About 6,000 miles of pipelines on the Alberta system, 
ranging from 6 to 42 inches in diameter, installed or upgraded between 
the early 1970s and 2005;
     About 4,500 miles of pipelines on the Mainline system east 
of the Alberta-Saskatchewan border, ranging from 20 to 42 inches in 
diameter, installed or upgraded between the early 1970s and 2005; and
     More than 600 miles in the Foothills Pipe Line system, 
ranging from 36 to 40 inches in diameter, installed between 1979 and 
1998.
    In the United Kingdom, about 1,140 miles of the Northern pipeline 
system has been uprated to operate at higher stress level in the past 
ten years.
    In the United States, some 5,000 miles of gas transmission lines 
that were grandfathered under Sec.  192.619(c) when the Federal 
pipeline safety regulations were adopted in the early 1970s continue to 
operate at stress levels higher than 72 percent of SMYS. After some 
accidents caused by corrosion on grandfathered pipelines, PHMSA 
considered whether to remove the exception in Sec.  192.619(c). In 
1992, PHMSA decided to continue to allow operation at the grandfathered 
pressures (57 FR 41119; Sept. 9, 1992). PHMSA based its decision on the 
operating history of two of the operators whose pipelines contained 
most of the mileage operated at the grandfathered pressures. PHMSA 
noted the incident rate on these

[[Page 13171]]

pipelines, operated at stress levels above 72 percent of SMYS, was 
between 10 percent and 50 percent of the incident rate of pipelines 
operated at the lower pressure. Texas Eastern Gas Pipeline Company (now 
Spectra Energy), the operator of many of the grandfathered pipelines, 
attributed the lower incident rate to aggressive inspection and 
maintenance. This included initial hydrostatic testing to 100 percent 
of SMYS, internal inspection, visual examination of anomalies found 
during internal inspection, repair of defects, and selective pressure 
testing to validate the results of the internal inspection. Internal 
inspection was not in common use in the industry prior to the 1980s. 
PHMSA's statistics show these pipelines continue to have an equivalent 
safety record when compared with pipelines operating according to the 
design factors in the pipeline safety regulations.
    PHMSA also considered technical studies and required companies 
seeking special permits to provide information about the pipeline's 
design and construction and to specify the additional inspection and 
testing to be used. PHMSA also considered how to handle findings that 
could compromise the long term serviceability of the pipe. PHMSA 
concluded that pipelines can operate safely and reliably at stress 
levels up to 80 percent of SMYS if the pipeline has well-established 
metallurgical properties and can be managed to protect it against known 
threats, such as corrosion and mechanical damage.
    Early and vigilant corrosion protection reduces the possibility of 
corrosion occurring. At the earliest stage, this includes care in 
applying a protective coating before transporting the pipe to the 
right-of-way. With the newer coating materials and careful application, 
coating provides considerable protection against external corrosion and 
facilitates the application of induced current, commonly called 
cathodic protection, to prevent corrosion from developing at any breaks 
that may occur in the coating. Regularly monitoring the level of 
protection and addressing any low readings corrects conditions that can 
cause corrosion at an early stage. Vigilant corrosion protection 
includes close attention to operating conditions that lead to internal 
corrosion, such as poor gas quality. In addition, for new pipelines, 
operators' compliance with a rule issued earlier this year requiring 
greater attention to internal corrosion protection during design and 
construction (72 FR 20059; Apr. 23, 2007) will prevent internal 
corrosion. Finally, corrosion protection includes internal inspection 
and other assessment techniques for early detection of both internal 
and external corrosion.
    One of the major causes of serious pipeline failure is mechanical 
damage caused by outside forces, such as an equipment strike during 
excavation activities. Burying the pipeline deeper, increased 
patrolling, and additional line marking helps prevent the risk that 
excavation will cause mechanical damage. Further, enhanced pipe 
properties increase the pipe's resistance to immediate puncture from a 
single equipment strike. Improved toughness increases the ability of 
the pipe to withstand mechanical damage from an outside force and also 
may also limit any failure consequences to leaks rather than ruptures. 
This toughness usually allows time for the operator to detect the 
damage during internal inspection well before the pipe fails.
    To evaluate each request, PHMSA established a docket and sought 
public comment on the request. We received few public comments, most in 
response to the first special permits considered. Many of the comments 
supported granting the special permits. Those who did not may have been 
unappreciative of the significance of the safety upgrades required for 
the special permits. A few raised technical concerns. Among these were 
questions about the impact of rail crossings and blasting activities in 
the vicinity of the pipeline. The special permits did not change the 
current requirements where road crossings exist and added a requirement 
to monitor activities, such as blasting, that could impact earth 
movement. Some commenters expressed concern about the impact radius of 
the pipeline operating at a higher stress level. PHMSA included 
supplemental safety criteria to address the increased radius. The 
remainder of the comment addressed concerns, such as compensation or 
aesthetics, which were outside the scope of the special permits. PHMSA 
permits do not address issues on siting, which is governed by the 
Federal Energy Regulatory Commission.
    PHMSA has now issued several special permits in response to these 
requests and continues to receive and evaluate other requests. The 
following table identifies the status of special permit requests and 
the dockets containing additional information about them.

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

    In each case, PHMSA provides oversight to confirm the line pipe is, 
or will be, as free of inherent flaws as possible, that construction 
and operation do not introduce flaws, and that any flaws are detected 
before they can fail. PHMSA accomplishes this by imposing a series of 
conditions on the grant of special permits. The conditions are designed 
to address the potential additional risk involved in operating the 
pipeline at a higher stress level. A proposed pipeline must be built to 
rigorous design and construction standards, and the operator requesting 
a

[[Page 13172]]

special permit for an existing pipeline must be able to demonstrate 
that the pipeline has been built to rigorous design and construction 
standards. These additional design and construction standards focus on 
producing a high quality pipeline that is free from inherent defects 
that could grow more rapidly under operation at a higher stress level 
and more resistant to expected operational risks. In addition, the 
operator of a pipeline receiving a special permit must comply with 
operation and maintenance requirements that exceed current pipeline 
safety regulations. These additional operation and maintenance 
requirements focus on the potential for corrosion and mechanical damage 
and on detecting defects before the defects can grow to failure.

B.5. Codifying the Special Permits

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

[[Page 13173]]

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

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

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

B.7. Statutory Considerations

    Under 49 U.S.C. 60102(a), PHMSA has broad authority to issue safety 
standards for the design, construction, operation, and maintenance of 
gas transmission pipelines. Under 49 U.S.C. 60104(b), PHMSA may not 
require an operator to modify or replace existing pipeline to meet a 
new design or construction standard. Although this proposal includes 
design and construction standards, these standards simply add more 
rigorous, non-mandatory requirements. This proposal does not require an 
operator to modify or replace existing pipeline or to design and 
construct new pipeline in accordance with these non-mandatory 
standards. If, however, a new or existing pipeline meets these more 
rigorous standards, the proposal would allow an operator to elect to 
calculate the MAOP for the pipeline based on a higher stress level. 
This would allow operation at an increased pressure over that otherwise 
allowed for pipeline built since the Federal regulations were issued in 
the 1970s. To operate at the higher pressure, the operator would have 
to comply with more rigorous operation and maintenance requirements.
    Under 49 U.S.C. 60102(b), a gas pipeline safety standard must be 
practicable and designed to meet the need for gas pipeline safety and 
for protection of the environment. PHMSA must consider several factors 
in issuing a safety standard. These factors include the relevant 
available pipeline safety and environmental information, the 
appropriateness of the standard for the type of pipeline, the 
reasonableness of the standard, and reasonably identifiable or 
estimated costs and benefits. PHMSA has considered these factors in 
developing this proposed rule and provides its analysis in the 
preamble.
    PHMSA must also consider any comments received from the public and 
any comments and recommendations of the Technical Pipeline Safety 
Standards Committee (Committee). Both the public and the Committee have 
already reviewed the concepts underlying this proposal. As discussed 
above, PHMSA opened this docket and conducted a public meeting in 2006 
to discuss the potential for increasing MAOP. PHMSA subsequently 
briefed the Committee. Finally, PHMSA has sought public comment on 
several requests for special permits to allow operation at increased 
MAOP. PHMSA considered the Committee discussion and public comment in 
developing this proposed rule. This notice of proposed rulemaking seeks 
public comment on the proposed rule; the Committee will formally 
consider it in a future meeting. PHMSA will address the public comments 
and the Committee's recommendations in preparing final action.

C. The Proposed Rule

C.1. In General

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

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

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

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

    The proposed rule would add a new section to Subpart C--Pipe Design 
in 49 CFR Part 192. The new section, Sec.  192.112 would prescribe 
additional design standards required for the steel pipeline to be 
qualified for operation at an alternative MAOP based on higher stress 
levels. These include requirements for rigorous steel chemistry and 
manufacturing practices and standards. Pipelines designed under these 
standards contain pipe with toughness properties to resist damage from 
outside forces and to control fracture initiation and growth. The 
considerable attention paid to the quality of seams, coatings, and 
fittings would prevent flaws leading to pipe failure. Unlike other 
design standards, Sec.  192.112 would apply to a new or existing 
pipeline only to the extent that an operator elects to operate at a 
higher

[[Page 13174]]

MAOP than allowed in current regulations.
    Proposed paragraph (a) sets high manufacturing standards for the 
steel plate or coil used for the pipe. These include reducing oxygen 
content to produce more uniform chemistry in the plate and limiting the 
use of alloys in place of carbon. The pipe would be manufactured in 
accordance with level 2 of API Specification 5L, with the wall 
thickness and the ratio between diameter and wall thickness limited to 
prevent the occurrence of denting and ovality during construction or 
operation. Improved construction and inspection practices discussed 
elsewhere in this notice of proposed rulemaking also help prevent 
denting and ovality.
    Proposed paragraph (b) addresses fracture control of the metal. 
First the metal would have to be tough; that is, deform plastically 
before fracturing. To the extent that the accepted industry toughness 
standard does not explicitly address the particular pipe used and 
expected operating conditions, correction factors would have to be 
used. Second, the pipe would have to pass several tests designed to 
reduce the risk that fractures would initiate. Third, to the extent it 
would be physically impossible for particular pipe to meet toughness 
standards under certain conditions, crack arrestors would have to be 
added to stop a fracture within a specified length.
    Proposed paragraph (c) provides tests to verify that there are no 
deleterious imperfections in the plate or coil. The macro-etch test 
will identify flaws that impact the surface of the plate or coil. 
Interior flaws will show up in ultrasonic testing.
    In addition to the quality of the steel, the integrity of a pipe 
depends on the integrity of the seams. Proposed paragraph (d) provides 
for a quality assurance program to assure tensile strength and 
toughness of the seams so that they resist breaking under regular 
operations. Hardness and ultrasonic tests would ensure that the seams 
also resist puncture damage.
    Proposed paragraph (e) would require a longer mill test pressure 
for new pipe at a higher hoop stress than required by current 
regulations. The mill test is used to discover flaws introduced in 
manufacture. Because the pipeline will be operated at a higher stress 
level, the more rigorous mill test is needed to match (or exceed) the 
level of safety provided for pipelines operated at less than 72 percent 
of SMYS.
    Proposed paragraph (f) would set rigorous standards for factory 
coating designed to protect the pipe from external corrosion. A quality 
assurance program would address all aspects of the application of 
coating that will protect the pipe. This would include applying a 
coating resistant to damage during installation of the pipe and 
examining the coated pipe to determine whether the applied coating is 
uniform and without gaps. Thin spots or holes in the coating make it 
more likely for corrosion to occur and more difficult to protect the 
pipe cathodically.
    Proposed paragraph (g) would require that factory-made fittings, 
induction bends, and flanges be certified as to their serviceability. 
In addition, the amount of non-carbon added in the steel for these 
fittings and flanges would be limited.
    Proposed paragraph (h) would require compressor design to limit the 
temperature of discharge to a specified maximum. Higher temperature can 
damage pipe coating. An exception to the specified maximum is allowed 
if testing of the coating shows it can withstand a higher temperature. 
The testing must be of sufficient length and rigor to detect coating 
integrity issues.

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

    The proposed rule would also add a new section to Subpart G--
General Construction Requirements for Transmission Lines and Mains. The 
new section, Sec.  192.328, would prescribe additional construction 
requirements, including rigorous quality control and inspections, as 
conditions for operation of the steel pipeline at higher stress levels. 
These include requirements for rigorous quality control and inspection 
during construction. Unlike other construction standards, Sec.  192.328 
would apply to a new or existing pipeline only to the extent that an 
operator elects to operate at a higher MAOP than allowed in current 
regulations.
    Proposed paragraph (a) would require a quality assurance plan for 
construction. Quality assurance, also called quality control, is common 
in modern pipeline construction. Activities such as lowering the pipe 
into the ditch and backfilling, if poorly done, can damage the pipe. 
Other construction activities such as nondestructive examination, if 
poorly done, will result in flaws remaining in the pipeline. Using a 
quality assurance plan helps to verify that the basic tasks done during 
construction of a pipeline are done correctly.
    Field application of coating is one of these basic tasks to be 
covered in a quality assurance plan. During the course of analyzing 
requests for special permits, PHMSA discovered field coatings at one 
construction site which were applied at lower temperature than needed 
for good adhesion to the pipe. Because coating is so critical to 
corrosion protection, proposed paragraph (a) would require quality 
assurance plans to contain specific performance measures for field 
coating. Field coating would have to meet substantially the same 
standards as coating applied at the mill and the individuals applying 
the coating would have to be appropriately trained and qualified.
    Proposed paragraph (b) would require non-destructive testing of all 
girth welds. Although past industry practice has been to non-
destructively test only a sample of girth welds, no alternative exists 
for verifying the integrity of the remaining welds. The initial 
pressure testing once construction is complete does not detect flaws in 
girth welds. PHMSA believes that most modern pipeline construction 
projects include non-destructive testing of all girth welds. However, 
because the regulations do not require testing of all girth welds, an 
operator's records for pipelines already in operation may not be 
complete. To account for this, proposed paragraph (b) would require 
testing records for only 95 percent of girth welds on existing 
segments.
    Proposed paragraph (c) would require deeper burial of segments 
operated at higher stress level. A greater depth of cover decreases the 
risk of damage to the pipeline from excavation, including farming 
operations.
    Proposed paragraph (d) addresses the results of the initial 
strength test and the assurance these results provide that the material 
in the pipeline is free of pre-operational flaws which can grow to 
failure over time. Since the initial strength test is a destructive 
test, it only detects flaws relatively close to failure during 
operation. This could leave in place smaller flaws that could grow more 
rapidly at higher stress level. To prevent this from occurring, the 
proposed paragraph would disqualify any segment which experiences a 
failure during the initial strength test indicative of systemic flaws 
in the material.
    Proposed paragraph (e) addresses cathodic protection on an existing 
segment. Applying this requirement to new segments is unnecessary since 
current regulations already require cathodic protection within 12 
months of construction. Proposed paragraph (e) would prevent an 
existing segment not cathodically protected within 12 months after 
construction from qualifying for operation at a higher stress level 
under this proposed regulation.

[[Page 13175]]

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

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

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

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

    The proposed rule would add a new section, Sec.  192.620, to 
subpart L of part 192, to specify what an operator would have to do in 
order to elect an alternative MAOP based on higher stress levels. The 
proposed rule would apply to both new and existing pipelines.
C.6.1. Calculating the Alternative MAOP
Proposed Sec.  192.620(a)
    Proposed paragraph (a) describes how to calculate the alternative 
MAOP based on the higher stress levels. Qualifying segments of pipe 
would use higher design factors to calculate the alternative MAOP. For 
a segment currently in operation this would result in an increase in 
MAOP. No changes would be made in the design factors used for segments 
within compressor or meter stations or segments underlying certain 
crossings.
C.6.2. Which Pipeline Qualifies
Proposed Sec.  192.620(b)
    Proposed paragraph (b) describes which segments of new or existing 
pipeline are qualified for operation at the alternative MAOP. The 
alternative MAOP would be allowed only in Class 1, 2, and 3 locations. 
Only steel pipelines meeting the rigorous design and construction 
requirements of Sec. Sec.  192.112 and 192.328 and monitored by 
supervisory data control and acquisition systems would qualify. 
Mechanical couplings in lieu of welding would not be allowed. Although 
the special permits did not expressly mention mechanical couplings, 
PHMSA would not have granted a special permit if the pipeline involved 
had mechanical couplings.
C.6.3. How an Operator Selects Operation Under This Section
Proposed Sec. Sec.  192.620(c)(1) and (2)
    Proposed paragraphs (c)(1) and (2) would require an operator to 
notify PHMSA when it elects to establish the MAOP under this section. 
An operator notifies PHMSA of the election by submitting a 
certification by a senior executive that the pipeline meets the 
rigorous additional design and construction regulations of this 
proposed rule. A senior executive must also certify that the operator 
has changed its operation and maintenance procedures to include the 
more rigorous additional operation and maintenance requirements of the 
proposed rule. In addition, a senior executive must certify that the 
operator has reviewed its damage prevention program in light of 
industry consensus standards and practices and made any needed changes 
to it to ensure that the program meets or exceeds those standards or 
practices. An operator would have to submit the certification at least 
180 days prior to commencing operations at the MAOP established under 
this section. This will provide PHMSA sufficient time for appropriate 
inspection which may include checks of the manufacturing process, 
visits to the pipeline construction sites, analysis of operating 
history of existing pipelines, and review of test records, plans, and 
procedures.
C.6.4. Initial Strength Testing
Proposed Sec.  192.620(c)(3)
    Proposed paragraph (c)(3) addresses initial strength testing 
requirements. In order to establish the MAOP under this section, an 
operator would have to perform the initial strength testing of a new 
segment at a pressure at least as great as 125 percent of the MAOP. 
Since an existing pipeline was previously operated at a lower MAOP, it 
may have been initially tested at a pressure less than 125 percent of 
the higher MAOP allowed under this section. If so, paragraph (c) would 
allow the operator to elect to conduct a new strength test in order to 
raise the MAOP.
C.6.5. Operation and Maintenance
Proposed Sec.  192.620(c)(4)
    Proposed paragraph (c)(4) would require an operator to comply with 
the additional operating and maintenance requirements of paragraph (d). 
Compliance with these additional requirements is required if an 
operator elects to calculate the MAOP for a segment under paragraph (a) 
and notifies PHMSA of that election under paragraph (c)(1) of this 
section.
C.6.6. New Construction and Maintenance Tasks
Proposed Sec.  192.620(c)(5)
    Proposed paragraph (c)(5) addresses the need for competent 
performance of both new construction, and future maintenance 
activities, to ensure the integrity of the segment. PHMSA now requires 
operators to ensure that individuals who perform pipeline operation and 
maintenance activities are qualified. During a 2005 review of the 
qualifications program, PHMSA discussed the need to ensure that 
construction-related activities are properly done:

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

[[Page 13176]]

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

    FDMS Docket ID PHMSA-RSPA-2004-19857-56, p. 2. Proposed paragraph 
(c)(5) would require operators seeking to operate at the higher stress 
levels allowed under this section to take steps designed to reduce 
incidents caused by errors during new construction and maintenance 
activities. As part of the 2005 review of the qualifications program, 
PHMSA sought comment on a broad approach to ensuring that construction-
related activities are done properly. Proposed paragraph (c)(5) would 
incorporate this approach. The approach would allow an operator to 
select an appropriate way to verify the proper performance of a 
construction-related activity. For example, non-destructive testing of 
all girth welds will significantly reduce the risk of a future weld 
failure. An operator could also effectively use quality controls during 
construction or qualify the individuals performing the tasks. Both 
industry consensus standards, and subpart N, provide models for 
qualifying individuals performing safety tasks.
C.6.7. Recordkeeping
Proposed Sec.  192.620(c)(6)
    Proposed paragraph (c)(6) clarifies recordkeeping requirements for 
operators electing to establish the MAOP under this section. Existing 
regulations, such as Sec. Sec.  192.13, 192.517(a), and 192.709, 
already require operators to maintain records applicable to this 
section. However, because the additional requirements proposed in this 
section address requirements found in other subparts of part 192, the 
recordkeeping requirements may cause confusion. For example, proposed 
Sec.  192.620(d)(9) would require a baseline assessment for integrity 
for a segment operated at the higher stress level regardless of its 
potential impact on a high consequence area. Section 192.947 requires 
operators to maintain records of baseline assessments for the useful 
life of the pipeline. However, proposed new Sec.  192.620 would be in 
subpart L. Section 192.709 requires an operator to retain records for 
an inspection done under subpart L for a more limited time. 
Accordingly, this paragraph would clarify the need to maintain all 
records demonstrating compliance for the useful life of the pipeline.

C.7. Additional Operation and Maintenance Requirements

Proposed Sec.  192.620(d)
    Paragraph (d) sets forth 11 operating and maintenance requirements 
that supplement the existing requirements in part 192. Current Sec.  
192.605 requires an operator to develop operation and maintenance 
procedures to implement the requirements of subpart L and M. Since 
proposed Sec.  192.620(d) is in subpart L, an operator would have to 
develop and follow the operation and maintenance procedures developed 
under this section. These include requirements for an operator to 
evaluate and address the issues associated with operating at higher 
pressures. Through its public education program, an operator would 
inform the public of any risks attributable to higher pressure 
operations. The additional operating and maintenance requirements 
address the two main risks the pipelines face, excavation damage and 
corrosion, through a combination of traditional practices and integrity 
management. Traditional practices include cathodic protection, control 
of gas quality, and maintenance of burial depth. Integrity management 
includes internal inspection on a periodic basis to identify and repair 
flaws before they can fail. These are discussed in more detail below.
C.7.1. Threat Assessments
Proposed Sec.  192.620(d)(1)
    Proposed paragraph (d)(1) would require preparation of a threat 
assessment consistent with that done under integrity management to 
address the risks of operating at an increased stress level. This 
proposed requirement is not limited to high consequence areas, but 
applies to the entire segment operating at the increased stress level.
    This proposed requirement comes from our experience with integrity 
management and special permits. Under integrity management, operators 
develop a detailed threat matrix identifying the risks associated with 
operating their pipelines. These risks include both general risks faced 
by all pipelines and those risks specific to the particular pipeline 
and its environment. The matrix lists specific threats and the 
mitigative measures an operator is using to address each threat. As 
applied to the special permits, and in this proposed rule, this threat 
assessment ensures that an operator takes into account any additional 
risk operation at a higher stress level imposes.
C.7.2. Public Awareness
Proposed Sec.  192.620(d)(2)
    Proposed paragraph (d)(2) would require an operator to include any 
people potentially impacted by operation at a higher stress level 
within the outreach effort in its public education program required 
under existing Sec.  192.616. In order to identify this population, an 
operator would use a broad area measured from the centerline of the 
pipe plus, in high consequence areas, the potential impact circle 
recalculated to reflect operation at a higher stress level. This is 
intended to get necessary information for safety to the people 
potentially impacted by a failure.
C.7.3. Emergency Response
Proposed Sec.  192.620(d)(3)
    Proposed paragraph (d)(3) addresses the additional needs for 
responding to emergencies for operation at higher stress levels. 
Consistent with the conditions imposed in the special permits, and past 
experience with response issues, the paragraph would require methods 
such as remote control valves to provide more rapid shut-down in the 
event of an emergency.
C.7.4. Damage Prevention
Proposed Sec.  192.620(d)(4)
    Proposed paragraph (d)(4) addresses one of the major risks of 
failure faced by a pipeline, damage from outside force such as damage 
occurring during excavation in the right-of-way. Although the improved 
toughness of pipe reduces the risk of damage, it does not prevent it 
and additional measures are appropriate for pipelines operating at 
higher stress levels. This paragraph proposes to add several new or 
more specific measures to existing requirements designed to prevent 
damage to pipelines from outside force. Additional attention to this 
area is important since the trend line for incidents caused by outside 
force on gas transmission pipelines between 2002 and 2006 is 
increasing.
    The first more specific measure, in proposed paragraph (d)(4)(i), 
addresses patrolling, required for all transmission pipelines by Sec.  
192.705. More frequent patrols of the right-of-way prevent damage by 
giving the operator more accurate and timely information about 
potential sources of ground disturbance and other outside force damage. 
These include both naturally occurring conditions, such as wash outs, 
and human activity, such as construction in the vicinity of the 
pipeline. The proposed requirement would be for

[[Page 13177]]

patrols on the same frequency as for hazardous liquid pipelines (i.e., 
a minimum of 26 times a year). This is slightly more frequent than 
included in the special permits, but PHMSA believes that it is 
appropriate for a rule of general applicability.
    The increased patrols that would be required by this rulemaking, 
however, represent the majority of the incremental costs imposed by 
this rule. Therefore, PHMSA specifically requests comment on whether 
the number of patrols required optimally balances the potential risk 
reduction and increase in burden. We seek information on:
     Would patrolling less frequently such as four times per 
year (similar to requirements at highway and railroad crossings) 
provide a cost-effective alternative?
     How often are pipelines that currently operate at 80% of 
SMYS patrolled? How effective are these patrols in providing accurate 
and timely information about potential sources of ground disturbance 
and other outside force damage?
     How could operators incorporate patrolling in their risk 
management plan if PHMSA did not mandate a fixed frequency?
    Other more specific or new measures to address damage prevention 
include developing and implementing a plan to monitor and address 
ground movement, a proposed requirement of paragraph (d)(4)(ii). Ground 
movement such as earthquakes, landslides, and nearby demolition or 
tunneling can damage pipe. Since pipelines near the surface are more 
likely to be damaged by surface activities, proposed paragraph 
(d)(4)(iii) would require an operator to maintain the depth of cover 
over a pipeline. Line-of-sight markers alert excavators, emergency 
responders, and the general public of the presence and general location 
of pipelines. Proposed paragraph (d)(4)(iv) would require these markers 
to improve both damage prevention and enhance public awareness.
    Damage prevention programs are improving because of the work being 
done by the Common Ground Alliance, a national, non-profit educational 
organization dedicated to preventing damage to pipelines and other 
underground utilities. The Common Ground Alliance has compiled best 
practices applicable to all parties relevant to preventing damage to 
underground utilities and actively promotes their use. Proposed 
paragraph (d)(4)(v) would require operators electing to operate at 
higher stress levels to evaluate their damage prevention programs in 
light of industry consensus standards and practices. An operator would 
have to identify the standards or practices used and make appropriate 
changes to the damage prevention program. The resulting program would 
have to meet or exceed the identified standards or practices. This 
approach is consistent with annual reviews of operation and maintenance 
programs under Sec.  192.605. An operator would have to include in the 
certification required under proposed Sec.  192.620(c)(1) that the 
review and upgrade has occurred.
    Proposed paragraph (d)(4) would also require one measure not 
included as a condition in the special permits, namely a right-of-way 
management plan. In the past several years, PHMSA has seen recurring 
similarities in pipeline accidents on construction sites. In each case, 
better management of the pipeline right-of-way could have prevented the 
accidents. Better management would include closer attention to the 
qualifications of individuals critical to damage prevention, better 
marking practices, and closer oversight of the excavation. In 2006, 
PHMSA issued two advisory bulletins to alert operators of the need to 
pay closer attention to these important damage prevention issues. The 
first advisory bulletin described three accidents in which either 
operator personnel or contractors damaged gas transmission pipelines 
during excavation in the rights-of-way (ADB-06-01; 71 FR 2613; Jan. 17, 
2006). This bulletin advised operators to pay closer attention to 
integrating operator qualification regulations into excavation 
activities and providing that excavation is included as a covered task 
under operator qualification programs required by subpart N. The second 
advisory bulletin pointed to an additional excavation accident where 
the excavator struck an inadequately marked gas transmission pipeline 
(ADB-06-03; 71 FR 67703; Nov. 22, 2006). This advisory bulletin advised 
pipeline operators to pay closer attention to locating and marking 
pipelines before excavation activities begin and pointed to several 
good practices as well as the best practices described by the Common 
Ground Alliance. This proposed paragraph would require an operator 
electing to operate at a higher stress level to develop a plan to 
manage the protection of their right-of-way from excavation activities. 
Each operator already has a damage prevention program, under Sec.  
192.614, and a program to ensure qualification of pipeline personnel, 
under subpart N. This management plan would require the operator to 
integrate activities under those programs to provide better protection 
for the right-of-way of pipeline operated at higher stress level.
C.7.5. Internal Corrosion Control
Proposed Sec.  192.620(d)(5)
    Proposed paragraph (d)(5) would add specificity to the requirements 
for internal corrosion control now in pipeline safety standards for 
pipelines operated at higher stress levels. These internal corrosion 
control programs would have to include mandated use of filter 
separators, gas quality monitoring equipment, cleaning pigs, and 
inhibitors. Maximum levels of contaminants that could promote corrosion 
are set to be monitored quarterly. PHMSA believes the levels are fully 
consistent with the requirements in Federal Energy Regulatory 
Commission tariffs designed to prevent internal corrosion.
C.7.6. External Corrosion Control
Proposed Sec. Sec.  192.620(d)(6), (7), and (8)
    Since external corrosion is one of the greatest risks to the 
integrity of pipelines operating at higher stress levels, the special 
permits and this proposed rule contain several measures to prevent it 
from occurring. These include use of effective coating, addressing 
interference, early installation of cathodic protection, confirming the 
adequacy of coating and cathodic protection and diligent monitoring of 
cathodic protection levels. The quality of the coating and installation 
of cathodic protection are addressed in proposed sections on design and 
construction. The remaining external corrosion provisions are addressed 
here.
    Interference from overhead power lines, railroad signaling, stray 
currents, or other sources can interfere with the cathodic protection 
system and, if not properly mitigated, even accelerate the rate of 
external corrosion. Proposed paragraph (d)(6) would require an operator 
to identify and address interference early before damage to the pipe 
can occur.
    Proposed paragraph (d)(7) would require an operator to confirm both 
the effectiveness of the coating and the adequacy of the cathodic 
protection system soon after deciding on operation at higher stress 
levels. This is accomplished through indirect assessment, such as a 
close interval survey. After completion of the baseline internal 
inspection required by proposed Sec.  192.620(d)(9), an operator would 
have to integrate the results of that inspection with the indirect 
assessments. An operator would have to

[[Page 13178]]

also take remedial action to correct any inadequacies. In high 
consequence areas, an operator would have to periodically repeat 
indirect assessment to confirm that the cathodic protection system 
remains as functional as when first installed.
    Proposed paragraph (d)(8) would require more rigorous attention to 
ensure adequate levels of cathodic protection. Regulations now require 
an operator discovering a low reading, meaning a reduced level of 
protection, must act promptly to correct the deficiency. This section 
puts an outer limit of six months on the time for completion of the 
remedial action and restoration of an adequate level of cathodic 
protection. In addition, the operator would have to confirm, through a 
close interval survey, that adequate cathodic protection levels were 
restored.
C.7.7 Integrity Assessments
Proposed Sec. Sec.  192.620(d)(9) and (10)
    Among the most important ways of ensuring integrity during pipeline 
operations are the assessments done under the integrity management 
program requirements in subpart O. Proposed paragraphs (d)(9) and 
(d)(10) would require operators electing to operate at higher stress 
levels to perform both baseline and periodic assessments of the entire 
segment operating at the higher stress level, regardless of whether the 
segment is located in a high consequence area. The operator would have 
to use both a geometry tool and a high resolution magnetic flux tool 
for the entire segment. In very limited circumstances in which internal 
inspection is not possible because internal inspection tools cannot be 
accommodated, such as a short crossover segment connecting two 
pipelines in a right-of-way, an operator would substitute direct 
assessment. The operator would then integrate the information provided 
by these assessments with testing done under previously described 
paragraphs. This analysis would form the basis for mitigating measures 
described in the operator's threat assessment, and prompt repairs under 
proposed paragraph (d)(11).
C.7.8. Repair Criteria
Proposed Sec.  192.620(d)(11)
    The repair criteria under proposed paragraph (d)(11) for anomalies 
in a segment operating at a higher stress level are slightly more 
conservative than for other pipeline, including pipeline covered by a 
integrity management program. With the tougher pipe, better coating and 
seams, and careful attention to damage prevention and corrosion 
protection, a pipeline operated at higher stress levels should 
experience few anomalies needing evaluation. The higher stress levels 
of operation can allow more rapid growth of anomalies. Therefore, more 
conservative repair criteria are needed.

C.8. Overpressure Protection

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

D. Regulatory Analyses and Notices

D.1. Privacy Act Statement

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

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

    Due to billions of dollars in benefits, the Department of 
Transportation (DOT) considers this proposed rulemaking to be a 
significant regulatory action under section 3(f)(1) of Executive Order 
12866 (58 FR 51735; Oct. 4, 1993). Therefore, DOT submitted it to the 
Office of Management and Budget for review. This proposed rulemaking is 
also significant under DOT regulatory policies and procedures (44 FR 
11034; Feb. 26, 1979).
    PHMSA prepared a draft Regulatory Evaluation of the proposed rule. 
A copy is in Docket ID PHMSA-2005-23447. If you have comments about the 
Regulatory Evaluation, please file them as described under the 
ADDRESSES heading of this document.
    PHMSA estimates that the proposed rule will result in gas 
transmission pipeline operators uprating 3,500 miles of existing 
pipelines to an alternative MAOP. Additionally PHMSA estimates that, in 
the future, the proposed rule will result in an annual additional 700 
miles of new pipeline whose operators elect to use an alternative MAOP.
    PHMSA expects the benefits of the proposed rule to be substantial 
and greatly in excess of $100 million per year. This expectation is 
based on quantified benefits in excess of $100 million per year (see 
below), coupled with un-quantified benefits associated with the 
proposed rule that industry and PHMSA technical staff have identified. 
The expected benefits of the proposed rule that cannot be readily 
quantified include:
     Reductions in incident consequences
     Increases in pipeline capacity
     Increases in the amount of natural gas filling the line, 
commonly called line pack
     Reductions in capital expenditures on compressors for new 
pipelines
     Reductions in adverse environmental impacts
    In the case of new pipelines, the ability to use an alternative 
MAOP will make it possible to transport more product. Quantifying the 
value of this increased capacity is difficult, and no estimate has been 
developed for this analysis. Nonetheless, PHMSA expects the value of 
increased capacity due to use of alternative MAOP by gas pipelines to 
be significant. Estimates made with respect to the proposed trans-
Alaskan gas pipeline include an estimated increase of 14.2 million 
standard cubic feet of gas per day. In areas where production is 
already well-established, there is an even greater potential for 
increased pipeline capacity. For example, one recipient of a special 
permit estimated a daily increase of at least 62 million standard cubic 
feet of gas.
    Similarly, increases in line pack will produce enormous benefits 
which are difficult to quantify. The reduced amount of exterior storage 
capacity resulting from increased line pack may result in capital or 
operation and maintenance savings for the pipelines or their customers. 
Increased line pack increases the ability to continue gas delivery 
during short outages such as maintenance and to increase the amount of 
gas quickly during peak periods. These benefits are not readily 
quantifiable.
    The quantified benefits consist of
     Fuel cost savings
     Capital expenditure savings on pipe for new pipelines
    Of these, pipeline fuel cost savings is the most important 
contributor to the estimated benefits. Although these quantified 
benefits do not capture the full benefits of the proposed rule, they 
exceed $100 million per year.
    As a consequence of the proposed rule, PHMSA estimates that 
pipeline operators will realize annually recurring benefits due to fuel 
cost savings of $58.8 million that begin in the initial year after the 
rule goes into effect and $9.8 million that begin in each subsequent 
year. Additionally, PHMSA estimates that each year pipeline operators 
will

[[Page 13179]]

realize one-time benefits for savings in capital expenditures of $54.6 
million (since 700 miles of new pipeline operating at an alternative 
MAOP are added each year, the one-time benefits resulting from this 
added mileage will be the same each year.) The benefits of the proposed 
rule over 20 years are expected to be as presented in the following 
table:

    Table D.2.-1--Summary and Total for the Estimated Benefits of the
                              Proposed Rule
------------------------------------------------------------------------
                                                        Estimate of new
                                   Estimate for year  benefits occurring
             Benefit                1  (millions of   in each subsequent
                                   dollars per year)  year  (millions of
                                                       dollars per year)
------------------------------------------------------------------------
Reduced incident consequences...  Not quantified....  Not quantified.
Fuel cost savings...............  $49.0 (recurring).  $0.0 (recurring).
Reduced capital expenditures....  $54.6 (non-         $54.6 (non-
                                   recurring).         recurring).
Increased pipeline capacity.....  Not quantified....  Not quantified.
Increased line pack.............  Not quantified....  Not quantified.
Reduced adverse environmental     Not quantified....  Not quantified.
 impacts.
Other expected benefits.........  Not quantified....  Not quantified.
                                 ---------------------------------------
    Total.......................  $49.0 recurring +   $54.6 non-
                                   $54.6 non-          recurring.
                                   recurring.
------------------------------------------------------------------------

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

                  TABLE D.2.-2--Summary and Totals for the Estimated Costs of the Proposed Rule
----------------------------------------------------------------------------------------------------------------
                                             Cost by year after implementation  (thousands of dollars)
            Cost item            -------------------------------------------------------------------------------
                                          1st              2nd-10th              11th              12th-20th
----------------------------------------------------------------------------------------------------------------
Baseline internal inspections...  $29,119...........  None..............  None..............  None.
Additional internal inspections.  None..............  None..............  $17,471...........  $2,912 each year.
Anomaly repairs.................  $1,015............  None..............  $1,218............  $203 each year.
Remotely controlled valves......  $3,528............  $588 each year....  $588..............  $588 each year.
Threat assessments..............  $180..............  $30 each year.....  $30...............  $30 each year.
Patrolling......................  $10,080...........  $11,760 to $25,200  $26,880...........  $28,560 to
                                                                                               $42,000.
Notifying PHMSA.................  Nominal...........  Nominal...........  Nominal...........  Nominal.
                                 -------------------------------------------------------------------------------
    Total.......................  $43,922...........  $618 each year      $46,187...........  $3,733 each year
                                                       plus patrolling                         plus patrolling
                                                       costs.                                  costs.
----------------------------------------------------------------------------------------------------------------

    The present value of the costs evaluated over 20 years at a three 
percent discount rate would be $435 million, while the present value of 
the costs over 20 years at a seven percent discount rate would be $293 
million. The annualized costs at the 3% discount rate would be $29 
million, while the annualized costs at the 7% discount rate would be 
$28 million.
    Since the present value of the quantified benefits ($1,541 million 
at three percent and $1,098 million at seven percent) exceeds the 
present value of the costs ($435 million at three percent and $293 
million at seven percent), the proposed rule is expected to be cost-
beneficial.

D.3. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether rulemaking actions would have a significant 
economic impact on a substantial number of small entities.
    The proposed rule would affect operators of gas pipelines. Based on 
annual reports submitted by operators, there are approximately 1,450 
gas transmission and gathering systems and an equivalent number of 
distribution systems potentially affected by the proposed rule. The 
size distribution of these operators is unknown and must be estimated.
    The affected gas transmission systems all belong to NAICS 486210, 
Pipeline Transportation of Natural Gas. In accordance with the size 
standards published by the Small Business Administration, a business 
with $6.5 million or less in annual revenue is considered a small 
business in this NAICS.
    Based on August 2006 information from Dunn & Bradstreet on firms in 
NAICS 486210, PHMSA estimates that 33% of the gas transmission and 
gathering systems have $6.5 million or less in revenue. Thus, PHMSA 
estimates that 479 of the gas transmission and gathering systems 
affected by the proposed rule will have $6.5 million or

[[Page 13180]]

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

D.4. Executive Order 13175

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

D.5. Paperwork Reduction Act

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

D.6. Unfunded Mandates Reform Act of 1995

    This proposed rule does not impose unfunded mandates under the 
Unfunded Mandates Reform Act of 1995. It does not result in costs of 
$100 million or more in any one year to either State, local, or tribal 
governments, in the aggregate, or to the private sector, and is the 
least burdensome alternative that achieves the objective of the 
proposed rulemaking.

D.7. National Environmental Policy Act

    PHMSA has analyzed the proposed rulemaking for purposes of the 
National Environmental Policy Act (42 U.S.C. 4321 et seq.). The 
proposed rulemaking would require limited physical change or other work 
that would disturb pipeline rights-of-way. In addition, the proposed 
rulemaking would codify the terms of special permits PHMSA has granted. 
Although PHMSA sought public comment on environmental impacts with 
respect to most requests for special permits to allow operation at 
pressures based on higher stress levels, no commenters addressed 
environmental impacts. PHMSA has preliminarily determined the proposed 
rulemaking is unlikely to significantly affect the quality of the human 
environment. An environmental assessment document is available for 
review in the docket. PHMSA will make a final determination on 
environmental impact after reviewing the comments to this proposal.

D.8. Executive Order 13132

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

D.9. Executive Order 13211

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

List of Subjects in 49 CFR Part 192

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

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

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

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

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

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

Sec.  192.7  Incorporation by reference.

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

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

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

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

[[Page 13181]]

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

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

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure calculated 
under Sec.  192.620, a segment must meet the following additional 
design requirements:

------------------------------------------------------------------------
                                  The pipeline segment must meet this
To address this design issue:           additional requirement:
------------------------------------------------------------------------
(a) General standards for the  (1) The plate or coil used for the pipe
 steel pipe.                    must be micro-alloyed, fine grain, fully
                                killed, continuously cast steel with
                                calcium treatment.
                               (2) The carbon equivalents of the steel
                                used for pipe must not exceed 0.23
                                percent by weight, as calculated by the
                                Ito-Bessyo formula (Pcm formula), for
                                wall thickness of one inch (25 mm) or
                                less, and 0.25 percent for wall
                                thickness greater than one inch (25 mm).
                               (3) The ratio of the specified outside
                                diameter of the pipe to the specified
                                wall thickness must be less than 100.
                                The wall thickness must prevent denting
                                and ovality anomalies during
                                construction, strength testing and
                                anticipated operational stresses.
                               (4) The pipe must be manufactured using
                                API Specification 5L, product
                                specification level 2 (incorporated by
                                reference, see Sec.   192.7) for maximum
                                operating pressures and minimum
                                operating temperatures and other
                                requirements under this section.
(b) Fracture control.........  (1) The toughness properties for pipe
                                must address the potential for
                                initiation, propagation and arrest of
                                fractures in accordance with:
                                  (i) API Specification 5L (incorporated
                                   by reference, see Sec.   192.7); and
                                  (ii) Any correction factors needed to
                                   address pipe grades, pressures,
                                   temperatures, or gas compositions not
                                   expressly addressed in API
                                   Specification 5L, product
                                   specification level 2 (incorporated
                                   by reference, see Sec.   192.7).
                               (2) Fracture control must:
                                  (i) Ensure resistance to fracture
                                   initiation while addressing the full
                                   range of operating temperatures,
                                   pressures and gas compositions the
                                   pipeline is expected to experience;
                                  (ii) Address adjustments to toughness
                                   of pipe for each grade used and the
                                   decompression behavior of the gas at
                                   operating parameters;
                                  (iii) Ensure at least 99 percent
                                   probability of fracture arrest within
                                   eight pipe lengths with a probability
                                   of not less than 90 percent within
                                   five pipe lengths; and
                                  (iv) Include fracture toughness
                                   testing that is equivalent to that
                                   described in supplementary
                                   requirements SR5A, SR5B, and SR6 of
                                   API Specification 5L (incorporated by
                                   reference, see Sec.   192.7) and
                                   ensures ductile fracture and arrest
                                   with the following exceptions:
                                    (A) The results of the Charpy impact
                                     test prescribed in SR5A must
                                     indicate at least 80 percent
                                     minimum shear area for any single
                                     test on each heat of steel; and
                                    (B) The results of the drop weight
                                     test prescribed in SR6 must
                                     indicate 80 percent average shear
                                     area with a minimum single test
                                     result of 60 percent shear area for
                                     any steel test samples.
                               (3) If it is not physically possible to
                                achieve the pipeline toughness
                                properties of paragraphs (b)(1) and (2)
                                of this section, mechanical crack
                                arrestors of proper design and spacing
                                must be used to ensure fracture arrest
                                as described in paragraph (b)(2)(iii) of
                                this section.
(c) Plate/coil quality         (1) There must be a comprehensive mill
 control.                       inspection program to check for defects
                                and inclusions affecting pipe quality.
                               (2) This mill inspection program must
                                include:
                                  (i) A macro etch test or other
                                   equivalent method to identify
                                   inclusions that may form centerline
                                   segregation during the continuous
                                   casting process. Use of sulfur prints
                                   is not an equivalent method. The test
                                   must be carried out on the first or
                                   second slab of each sequence graded
                                   with an acceptance criteria of at
                                   least 2 on the Mannesmann scale or
                                   equivalent; and
                                  (ii) An ultrasonic test of the ends
                                   and at least 50 percent of the
                                   surface of the plate/coil or pipe to
                                   identify imperfections that impair
                                   serviceability such as laminations,
                                   cracks, and inclusions. At least 95
                                   percent of the lengths of pipe
                                   manufactured must be tested. For
                                   pipeline designed after [the
                                   effective date of the final rule],
                                   the test must be done in accordance
                                   with Level B of ASTM A 578/A578M
                                   (incorporated by reference, see Sec.
                                    192.7) or equivalent.
(d) Seam quality control.....  (1) There must be a quality assurance
                                program for pipe seam welds:
                                  (i) To assure tensile strength
                                   provided in API Specification 5L
                                   (incorporated by reference, see Sec.
                                    192.7) for appropriate grades; and
                                  (ii) To assure toughness of at least
                                   35 foot-pounds at 32 degrees
                                   Fahrenheit (or minimum operating
                                   temperature).
                               (2) There must be a hardness test, using
                                Vickers (Hv10) hardness test method or
                                equivalent test method to assure a
                                maximum hardness of 280 Vickers of the
                                following:
                                  (i) A cross section of the weld seam
                                   of one pipe from each heat plus one
                                   pipe from each welding line per day;
                                   and
                                  (ii) For each sample cross section, a
                                   minimum of 13 readings (three for
                                   each heat affected zone, three in the
                                   weld metal, and two in each section
                                   of pipe base metal).
                               (3) All of the seams must be
                                ultrasonically tested after cold
                                expansion and hydrostatic testing.
(e) Mill hydrostatic test....  (1) All pipe to be used in a new segment
                                must be hydrostatically tested at the
                                mill at a test pressure corresponding to
                                a hoop stress of 95 percent SMYS for 20
                                seconds, including the allowance for end
                                loading stresses.
                               (2) Pipe previously in operation must
                                have been hydrostatically tested at the
                                mill at a test pressure corresponding to
                                a hoop stress of 90 percent SMYS for 10
                                seconds.

[[Page 13182]]

(f) Coating..................  (1) The pipe must be protected against
                                external corrosion by non-shielding,
                                fusion bonded epoxy coating.
                               (2) Coating on pipe used for trenchless
                                installation must resist abrasions and
                                other damage possible during
                                installation.
                               (3) A quality assurance inspection and
                                testing program for the coating must
                                cover the surface quality of the bare
                                pipe, surface cleanliness and chlorides,
                                blast cleaning, application temperature
                                control, adhesion, cathodic disbondment,
                                moisture permeation, bending, coating
                                thickness, holiday detection, and
                                repair.
(g) Fittings and flanges.....  (1) There must be certification records
                                of flanges, factory induction bends and
                                factory weld ells.
                               (2) If the carbon equivalents of flanges,
                                bends and ells are greater than 0.42
                                percent by weight, the qualified welding
                                procedures must include a pre-heat
                                procedure.
(h) Compressor stations......  (1) A compressor station must be designed
                                to limit discharge temperature to a
                                maximum of 120 degrees Fahrenheit (49
                                degrees Centigrade) or the higher
                                temperature allowed in paragraph (h)(2)
                                of this section.
                               (2) If testing shows that the coating
                                will withstand a higher temperature in
                                long-term operations, the compressor
                                station may be designed to limit
                                discharge temperature to that higher
                                temperature.
------------------------------------------------------------------------

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

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

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure calculated 
under Sec.  192.620, a segment must meet the following additional 
construction requirements:

------------------------------------------------------------------------
 To address this construction     The pipeline segment must meet this
            issue:                additional construction requirement:
------------------------------------------------------------------------
(a) Quality assurance........  (1) The construction of the segment must
                                be done under a quality assurance plan
                                addressing pipe inspection, hauling and
                                stringing, field bending, welding, non-
                                destructive examination of girth welds,
                                applying and testing field applied
                                coating, lowering of the pipeline into
                                the ditch, padding and backfilling, and
                                hydrostatic testing.
                               (2) The quality assurance plan for
                                applying and testing field applied
                                coating to girth welds must be:
                                  (i) Equivalent to that required under
                                   Sec.   192.112(f)(3) for pipe; and
                                  (ii) Performed by an individual with
                                   the knowledge, skills, and ability to
                                   assure effective coating.
(b) Girth welds..............  (1) All girth welds on a new segment must
                                be non-destructively examined in
                                accordance with Sec.   192.243(b) and
                                (c).
                               (2) At least 95 percent of girth welds on
                                a segment that was constructed prior to
                                the effective date of this rule must
                                have been non-destructively examined in
                                accordance with Sec.   192.243(b) and
                                (c).
(c) Depth of cover...........  (1) Notwithstanding any lesser depth of
                                cover otherwise allowed in Sec.
                                192.327, there must be at least 36
                                inches (914 millimeters) of cover.
                               (2) In areas where deep tilling or other
                                activities could threaten the pipeline,
                                the top of the pipeline must be
                                installed at least one foot below the
                                deepest expected penetration of the
                                soil.
(d) Initial strength testing.  (1) The segment must not experience any
                                failures indicative of fault in material
                                during strength testing, including
                                initial hydrostatic testing.
(e) Cathodic protection......  (1) If the segment has been in operation,
                                the cathodic protection system on the
                                segment must have been operational
                                within 12 months of construction.
(f) Interference currents....  (1) For a new segment, the construction
                                must address the impacts of induced
                                alternating current from parallel
                                electric transmission lines and other
                                known sources of potential interference
                                with corrosion control.
------------------------------------------------------------------------

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

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

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

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

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

[[Page 13183]]

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

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

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

    (b) When may an operator use the alternative maximum allowable 
operating pressure calculated under paragraph (a) of this section? An 
operator may use a maximum allowable operating pressure calculated 
under paragraph (a) of this section if the following conditions are 
met:
    (1) The segment is in a Class 1, 2, or 3 location;
    (2) The segment is constructed of steel pipe meeting the additional 
design requirements in Sec.  192.112;
    (3) A supervisory control and data acquisition system provides 
remote monitoring and control of the segment;
    (4) The segment meets the additional construction requirements 
described in Sec.  192.328;
    (5) The segment does not contain any mechanical couplings used in 
place of girth welds; and
    (6) If a segment has been previously operated, the segment has not 
experienced any failure during normal operations indicative of a fault 
in material.
    (c) What is an operator electing to use the alternative maximum 
allowable operating pressure required to do? If an operator elects to 
use the maximum allowable operating pressure calculated under paragraph 
(a) of this section for a segment, the operator must do each of the 
following:
    (1) Certify, by signature of a senior executive officer of the 
company, as follows:
    (A) The segment meets the conditions described in subsection (b) of 
this section; and
    (B) The operating and maintenance procedures include the additional 
operating and maintenance requirements of subsection (d) of this 
section; and
    (C) The review and any needed program upgrade of the damage 
prevention program required by subsection (d)(4)(v) of this section has 
been completed.
    (2) Notify PHMSA of its election with respect to a segment at least 
180 days before operating at the alternative maximum allowable 
operating pressure by sending the certification to the Information 
Resources Manager as provided for reports under Sec.  192.951.
    (3) For each segment, do one of the following:
    (i) Perform a strength test as described in Sec.  192.505 at a test 
pressure of at least 125 percent of the maximum allowable operating 
pressure calculated under paragraph (a) of this section; or
    (ii) For a segment in existence prior to the effective date of this 
regulation, certify, under paragraph (c)(1) of this section, that the 
strength test performed under Sec.  192.505 was conducted at a test 
pressure of at least 125 percent of the maximum allowable operating 
pressure calculated under paragraph (a) of this section.
    (4) Comply with the additional operation and maintenance 
requirements described in paragraph (d) of this section.
    (5) If the performance of a construction task affects the integrity 
of the segment, ensure that the task is performed properly by doing at 
least one of the following:
    (i) Include quality controls during construction addressing 
performance of the task;
    (ii) Use an integrity verification method that addresses 
performance of the task; or
    (iii) Demonstrate that the individual performing the task has the 
knowledge, skills, and ability to do so.
    (6) Maintain, for the useful life of the pipeline, records 
demonstrating compliance with paragraphs (b), (c)(5), and (d) of this 
section.
    (d) What additional operation and maintenance requirements apply to 
operation at the alternative maximum allowable operating pressure? In 
addition to compliance with other applicable safety standards in this 
part, if an operator establishes a maximum allowable operating pressure 
for a segment under paragraph (a) of this section, an operator must 
comply with the additional operation and maintenance requirements as 
follows:

------------------------------------------------------------------------
 To address increased risk of
a maximum allowable operating
   pressure based on higher       Take the following additional step:
     stress levels in the
       following areas:
------------------------------------------------------------------------
(1) Assessing threats........  Develop a threat matrix consistent with
                                Sec.   192.917 to do the following:
                                  (i) Identify and compare the increased
                                   risk of operating the pipeline at the
                                   increased stress level under this
                                   section with conventional operation;
                                   and
                                  (ii) Describe procedures used to
                                   mitigate the risk.
(2) Notifying the public.....  (i) Recalculate the potential impact
                                circle as defined in Sec.   192.903 to
                                reflect use of the alternative maximum
                                operating pressure calculated under
                                paragraph (a) of this section and
                                pipeline operating conditions; and
                               (ii) In implementing the public education
                                program required under Sec.   192.616,
                                do the following:
                                  (A) Include persons occupying property
                                   within 220 yards of the centerline
                                   and within the potential impact
                                   circle within the targeted audience;
                                   and
                                  (B) Include information about the
                                   integrity management activities
                                   performed under this section within
                                   the message provided to the audience.
(3) Responding to an           (i) Ensure that the identification of
 emergency in an area defined   high consequence areas reflects the
 as a high consequence area     larger potential impact circle
 in Sec.   192.903.             recalculated under paragraph (d)(2)(i)
                                of this section.
                               (ii) If personnel response time to
                                mainline valves on either side of the
                                high consequence area exceeds one hour,
                                provide remote valve control through a
                                supervisory control and data acquisition
                                system, other leak detection system, or
                                an alternative method of control.
                               (iii) Remote valve control must include
                                the ability to open and close the valve,
                                monitor the position of the valve, and
                                monitor pressure upstream and
                                downstream.
                               (iv) A line break valve control system
                                using differential pressure, rate of
                                pressure drop or other widely-accepted
                                method is an acceptable alternative to
                                remote valve control.

[[Page 13184]]

(4) Protecting the right of    (i) Patrol the right of way at intervals
 way.                           not exceeding 3 weeks, but at least 26
                                times each calendar year, to inspect for
                                excavation activities, ground movement,
                                wash outs, leakage, or other activities
                                or conditions affecting the safety
                                operation of the pipeline.
                               (ii) Develop and implement a plan to
                                monitor for and mitigate occurrences of
                                unstable soil and ground movement.
                               (iii) Maintain the depth of cover
                                provided for new pipeline under Sec.
                                192.327 or Sec.   192.328(c). If
                                observed conditions indicate the
                                possible loss of cover, perform a depth
                                of cover study and replace cover as
                                necessary to restore the depth of cover.
                               (iv) Use line-of-sight line markers
                                satisfying the requirements of Sec.
                                192.707(d) except in agricultural areas,
                                large water crossings or where
                                prohibited by Federal Energy Regulatory
                                Commission orders, permits, or local
                                law.
                               (v) Review the damage prevention program
                                under Sec.   192.614(a) in light of
                                national consensus standards and
                                practices, to ensure the program
                                provides adequate protection of the
                                right-of-way. Identify the standards or
                                practices considered in the review, and
                                meet or exceed those standards or
                                practices by incorporating appropriate
                                changes into the program.
                               (vi) Develop and implement a right-of-way
                                management plan to protect the segment
                                from damage due to excavation
                                activities.
(5) Controlling internal       (i) Develop and implement a program to
 corrosion.                     monitor for and mitigate the presence
                                of, deleterious gas stream constituents.
                               (ii) At points where gas with potentially
                                deleterious contaminants enters the
                                pipeline, use filter separators and gas
                                quality monitoring equipment.
                               (iii) Use gas quality monitoring
                                equipment that includes a moisture
                                analyzer, chromatograph, and periodic
                                hydrogen sulfide sampling.
                               (iii) Use cleaning pigs and inhibitors,
                                and sample accumulated liquids.
                               (iv) Address deleterious gas stream
                                constituents as follows:
                                  (A) Limit carbon dioxide to 3 percent
                                   by volume;
                                  (B) Allow no free water and otherwise
                                   limit water to seven pounds per
                                   million cubic feet of gas; and
                                  (C) Limit hydrogen sulfide to 0.50
                                   grain per hundred cubic feet of gas.
                               (v) Review the program at least quarterly
                                based on the gas stream experienced and
                                implement adjustments to monitor for,
                                and mitigate the presence of,
                                deleterious gas stream constituents.
(6) Controlling interference   (i) Prior to operating an existing
 that can impact external       segment at a maximum allowable operating
 corrosion.                     pressure calculated under this section,
                                or within six months after placing a new
                                segment in service at a maximum
                                allowable operating pressure calculated
                                under this section, address interference
                                issues on the segment.
                               (ii) To address interference issues, do
                                the following:
                                  (A) Conduct an interference survey to
                                   detect the presence and level of any
                                   electrical current that could impact
                                   external corrosion;
                                  (B) Analyze the results of the survey;
                                   and
                                  (C) Take any remedial action needed to
                                   protect the segment from deleterious
                                   current.
(7) Confirming external        (i) Within six months after placing the
 corrosion control through      cathodic protection of a new segment in
 indirect assessment.           operation, or within six months after
                                recalculating the maximum allowable
                                operating pressure of an existing
                                segment under this section, assess the
                                integrity of the coating and adequacy of
                                the cathodic protection through an
                                indirect method such as close-interval
                                survey, direct current voltage gradient,
                                or alternating current voltage gradient.
                               (ii) Remediate any construction damaged
                                coating with a voltage drop classified
                                as moderate or severe indication under
                                section 4, table 3 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 (9) of this
                                section, integrate the results of the
                                indirect assessment required under
                                paragraph (7)(i) of this section with
                                the results of the baseline internal
                                inspection and take any needed remedial
                                actions.
                               (iv) For all segments in high consequence
                                areas, do 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.
                                  (C) Integrate the results with those
                                   of the baseline and periodic
                                   assessments for integrity done under
                                   paragraphs (d)(9) and (d)(10) of this
                                   section.
(8) Controlling external       (i) If an annual test station reading
 corrosion through cathodic     indicates cathodic protection below the
 protection.                    level of protection required in subpart
                                I of this part, complete remedial action
                                within six months of the failed reading;
                                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.
(9) Conducting a baseline      (i) Except as provided in paragraph
 assessment of integrity.       (d)(9)(iii) of this section, for a new
                                segment, do a baseline internal
                                inspection as follows:
                                  (A) Assess using a geometry tool after
                                   the initial hydrostatic test and
                                   backfill within six months after
                                   placing the new segment in service;
                                   and
                                  (B) Assess using a high resolution
                                   magnetic flux tool within three years
                                   after placing the new segment in
                                   service.

[[Page 13185]]

                               (ii) Except as provided in paragraph
                                (d)(9)(iii) of this section, for an
                                existing segment, do a baseline internal
                                assessment using a geometry tool and a
                                high resolution magnetic flux tool
                                before, but within two years prior to,
                                raising pressure as allowed under this
                                section.
                               (iii) If headers, mainline valve by-
                                passes, compressor station piping, meter
                                station piping, or other short portion
                                of a segment cannot accommodate a
                                geometry tool and a high resolution
                                magnetic flux tool, use direct
                                assessment to assess that portion.
(10) Conducting periodic       (i) Determine a frequency for subsequent
 assessments of integrity.      periodic inspections as if the segments
                                were covered by subpart O of this part.
                               (ii) Conduct periodic internal
                                inspections using a high resolution
                                magnetic flux tool on the frequency
                                determined under paragraph (d)(10)(i) of
                                this section.
                               (iii) Use direct assessment for periodic
                                assessment of a portion of a segment to
                                the extent permitted for a baseline
                                assessment under paragraph (d)(9)(iii)
                                of this section.
(11) Making repairs..........  (i) Do the following when evaluating an
                                anomaly:
                                  (A) Use the most conservative
                                   calculation for determining remaining
                                   strength or an alternative validated
                                   calculation based on pipe diameter,
                                   wall thickness, grade, operating
                                   pressure, operating stress level, and
                                   operating temperature: and
                                  (B) Take into account the tolerances
                                   of the tools used for the inspection.
                               (ii) Repair a defect immediately if any
                                of the following apply:
                                  (A) The defect is a dent discovered
                                   during the baseline assessment for
                                   integrity under paragraph (d)(9) of
                                   this section and the defect meets the
                                   criteria for immediate repair in Sec.
                                     192.309(b).
                                  (B) The defect meets the criteria for
                                   immediate repair in Sec.
                                   192.933(d).
                                  (C) The maximum allowable operating
                                   pressure was based on a design factor
                                   of 0.67 under paragraph (a) of this
                                   section and the failure pressure is
                                   less than 1.25 times the maximum
                                   allowable operating pressure.
                                  (D) The maximum allowable operating
                                   pressure was based on a design factor
                                   of 0.56 under paragraph (a) of this
                                   section and the failure pressure is
                                   less than or equal to 1.4 times the
                                   maximum allowable operating pressure.
                               (iii) If paragraph (d)(11)(ii) of this
                                section does not require immediate
                                repair, repair a defect within one year
                                if any of the following apply:
                                  (A) The defect meets the criteria for
                                   repair within one year in Sec.
                                   192.933(d).
                                  (B) The maximum allowable operating
                                   pressure was based on a design factor
                                   of 0.80 under paragraph (a) of this
                                   section and the failure pressure is
                                   less than 1.25 times the maximum
                                   allowable operating pressure.
                                  (C) The maximum allowable operating
                                   pressure was based on a design factor
                                   of 0.67 under paragraph (a) of this
                                   section and the failure pressure is
                                   less than 1.50 times the maximum
                                   allowable operating pressure.
                                  (D) The maximum allowable operating
                                   pressure was based on a design factor
                                   of 0.56 under paragraph (a) of this
                                   section and the failure pressure is
                                   less than or equal to 1.80 times the
                                   maximum allowable operating pressure.
                               (iv) Evaluate any defect not required to
                                be repaired under paragraph (d)(11)(ii)
                                or (iii) of this section to determine
                                its growth rate, set the maximum
                                interval for repair or re-inspection,
                                and repair or re-inspect within that
                                interval.
------------------------------------------------------------------------

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

    Issued in Washington, DC, on March 4, 2008.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. E8-4656 Filed 3-11-08; 8:45 am]

BILLING CODE 4910-60-P