Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines, 13167-13185 [E8-4656]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 73, Number 49 (Wednesday, March 12, 2008)]
[Proposed Rules]
[Pages 13167-13185]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-4656]


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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: https://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 https://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 https://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 discus