[Federal Register Volume 72, Number 77 (Monday, April 23, 2007)]
[Rules and Regulations]
[Pages 20055-20060]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-7701]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-2005-22642]
RIN 2137-AE09


Pipeline Safety: Design and Construction Standards To Reduce 
Internal Corrosion in Gas Transmission Pipelines

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

ACTION: Final rule.

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SUMMARY: This final rule requires operators to use design and 
construction features in new and replaced gas transmission pipelines to 
reduce the risk of internal corrosion. The design and construction 
features required by this rule will reduce the risk of internal 
corrosion and related pipeline failures by reducing the potential for 
accumulation of liquids and facilitating operation and maintenance 
practices that address internal corrosion.

DATES: This final rule takes effect May 23, 2007.

FOR FURTHER INFORMATION CONTACT: Barbara Betsock by phone at (202) 366-
4361, by fax at (202) 366-4566, or by e-mail at 
<a href="/cdn-cgi/l/email-protection#8fedeefdedeefdeea1edeafbfce0ece4cfebe0fba1e8e0f9"><span class="__cf_email__" data-cfemail="d1b3b0a3b3b0a3b0ffb3b4a5a2beb2ba91b5bea5ffb6bea7">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION: 

Background

    We initiated this rulemaking proceeding in response to a 2003 
recommendation of the National Transportation Safety Board (NTSB) and 
corresponding advice of the Technical Pipeline Safety Standards 
Committee (TPSSC). The NTSB recommendation arose out of its 
investigation of the August 19, 2000 gas transmission pipeline 
explosion near Carlsbad, New Mexico in which 12 people were killed. In 
its accident investigation report, PAR-03-01, issued February 11, 2003, 
the NTSB concluded that the immediate cause of the Carlsbad pipeline 
failure was severe internal corrosion. The NTSB recommended that PHMSA 
(1) require that new and replaced gas transmission pipelines be 
designed and constructed with features to mitigate internal corrosion; 
(2) require operators to ensure that their internal corrosion control 
programs address water and other contaminants in the corrosion process; 
and (3) change its Federal inspection to ensure adequate assessments of 
pipeline operator safety programs. In 2004 and 2005, the NTSB closed as 
acceptable PHMSA actions to respond to the second and third 
recommendations. This rulemaking proceeding responds to the first 
recommendation.
    On December 15, 2005, PHMSA published a notice of proposed 
rulemaking (NPRM) in the Federal Register (70 FR 74262) proposing to 
require operators to use design and construction features to reduce the 
risk of internal corrosion in transmission pipelines. As we explained 
in the NPRM, the proposed rule was intended to prevent the risk of 
internal corrosion by applying knowledge and experience about the 
causes and prevention of corrosion to design of pipelines. The 
incorporation of design features to address internal corrosion improves 
the ability of the operator to prevent internal corrosion and 
facilitates maintenance activities to control internal corrosion.
    The basic requirements of this final rule are similar to those 
proposed in the NPRM. New and replaced gas transmission pipelines must 
be configured to reduce the risk that liquids will collect in the line; 
have effective liquid removal features; and allow use of corrosion 
monitoring devices in locations with significant potential for internal 
corrosion. When an operator changes the configuration of a pipeline, 
the operator must consider and address the impact the changes will have 
on the risk of internal corrosion in an existing downstream pipeline. 
This final rule does not supersede or negate the requirement to address 
internal corrosion during operation and maintenance activities. 
Designing and building a pipeline in accordance with the final rule 
will not prevent internal corrosion unless the operator also follows a 
well-planned maintenance program. For example, incorporating equipment 
to measure gas quality will not prevent internal corrosion unless it is 
used and the operator acts on the results.

Advisory Committee Consideration

    PHMSA briefed the TPSSC in June 2005 and considered the Committee's 
advice in developing the NPRM. PHMSA presented the NPRM and regulatory 
evaluation to the TPSSC for formal consideration at their meeting on 
June 28, 2006. At that meeting, members expressed concern that the 
proposed documentation requirements were burdensome. TPSSC members 
asked for information about whether PHMSA intended to require detailed 
documentation of every action taken during design and construction; 
what alternatives commenters suggested; and how the NTSB reached its 
recommendation. PHMSA provided additional information in the form of a 
concept paper on the documentation needed for compliance, an expanded 
summary of comments, and excerpts from the NTSB report on the Carlsbad 
incident. PHMSA briefed the TPSSC at a meeting on August 26, 2006 and 
outlined changes we intended to make in response to comments. A few 
members expressed individual concerns about particular issues. These 
concerns are addressed in the remainder of this preamble. The TPSSC 
voted unanimously to support the NPRM as technically feasible, 
reasonable, cost-effective and practicable, provided the final rule 
included the changes PHMSA outlined at the meeting. In addition, the 
TPSSC advised PHMSA to hold discussions in an open forum on enforcement 
criteria, including protocol development and recordkeeping. The final 
rule is consistent with the discussion at the TPSSC meeting. In 
accordance with the TPSSC's advice, PHMSA intends to convene an open 
forum soon after the final rule is issued.

Comments on the NPRM

    PHMSA received public comments on the NPRM from 18 commenters, 13 
of them operators of gas transmission pipelines. The Gas Piping 
Technology Committee, Interstate Natural Gas Association of America, 
American Gas Association, the Texas Pipeline Association, and the Iowa 
Utilities Board also commented. Commenters agreed with the basic 
concept of the proposal--addressing internal corrosion risks during 
design and construction. Most commenters viewed the documentation 
requirements of the proposed rule as burdensome. Some expressed 
confusion about what an operator would have to do to comply. As an 
example, some questioned

[[Page 20056]]

whether the proposed rule would require an operator to conduct an 
engineering analysis to justify variations in elevation due to 
following the contours of the land. PHMSA has revised the rule text to 
clarify the final rule and refine the documentation requirements to 
ensure compliance without excessive burden. We discuss the major 
comments and how we are addressing them more specifically in the 
following paragraphs.

Redundancy

    Some commenters contend existing regulations in 49 CFR part 192 
make this rulemaking redundant and unnecessary. These commenters point 
to regulations requiring operators to design new pipeline to allow the 
use of instrumented internal inspection devices (Sec.  192.150); to 
check for internal corrosion when pipe is removed (Sec.  192.475); to 
maintain continuing surveillance (Sec.  192.613); and to develop 
integrity management programs addressing internal corrosion (subpart 
O). However, none of the regulations cited by commenters squarely 
addresses the goals of this rulemaking and the NTSB recommendation.
    The purpose of Sec.  192.150 is to allow internal inspection to 
address a variety of pipeline risks. Section 192.150 incidentally aids 
internal corrosion control because a pipeline designed to allow 
internal inspection can also accommodate cleaning pigs. Cleaning pigs 
remove liquids and contaminants from a pipeline as part of corrosion 
control. In its report on the 2000 Carlsbad incident, the NTSB 
recognized the value of cleaning pigs and their limitations in 
addressing the internal corrosion issues in the Carlsbad incident.\1\ 
The NTSB recommended additional regulation to require design features 
focused on internal corrosion. In addition, unlike this final rule, 
Sec.  192.150 does not apply to gathering lines.
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    \1\ From NTSB report PAR 03-01:
    The Safety Board concludes that, as a likely result of the 
partial clogging of the drip upstream of the rupture location, some 
liquids bypassed the drip, continued through the pipeline, and 
accumulated and caused corrosion at the eventual rupture site where 
pipe bending had created a low point in the pipeline.
    Periodic use of cleaning pigs can remove water and other liquid 
and solid contaminants from a pipeline. One of the considerations 
for the design and construction of a cleaning pig system is to make 
provisions for effective collection and removal of the accumulated 
materials from the pipeline after pigging [* * *]
    [* * *] The Safety Board therefore concludes that if the 
accident section of pipeline 1103 had been able to accommodate 
cleaning pigs, and if cleaning pigs had been used regularly with the 
resulting liquids and solids thoroughly removed from the pipeline 
after each pig run, the internal corrosion that developed in this 
section of pipe would likely have been less severe.
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    The regulations requiring an operator to check line pipe removed 
from a pipeline for signs of internal corrosion (Sec.  192.475) and to 
maintain continuing surveillance (Sec.  192.613) are not design 
requirements. These regulations are among those operation and 
maintenance regulations requiring operators to monitor their pipelines 
and collect and analyze information about safety risks. But these 
practices usually only enable operators to detect signs of corrosion. 
The actions recommended by the NTSB and addressed in this final rule 
reduce the risk that internal corrosion will even initiate by designing 
and constructing pipelines to reduce that risk in the first place. 
Requiring operators to design their systems to reduce the risk of 
internal corrosion neither duplicates nor obviates the need to detect 
and monitor internal corrosion.
    Some commenters said the proposed rule did not take into account 
the internal corrosion management plans required by the integrity 
management regulations (subpart O). In fact, we believe that the final 
rule will complement the existing requirements under subpart O. Subpart 
O applies only to pipelines in high consequence areas (HCAs). In those 
areas, it supplements the safety protection provided by the minimum 
standards. This final rule sets a minimum standard for design and 
construction applicable to all onshore pipelines, regardless of 
location. For pipeline in an HCA, compliance with the new standard will 
facilitate addressing the risk of internal corrosion under an integrity 
management program. For example, Sec.  192.927(c)(4) requires an 
operator to continually monitor covered segments where internal 
corrosion has been identified. A segment constructed in accordance with 
this final rule will have liquid removal features and allow the use of 
appropriate monitoring devices.

Exceptions Based on What the Operator Expects To Occur During 
Operations

    Many commenters requested an exception to the design and 
construction requirements if the operator believes liquids will not 
pose a problem in the line. Commenters suggested several variations. 
Some commenters suggested that we establish an exception applicable if 
the operator confirms liquids will not present an uncontrolled threat 
(presumably because of planned corrosion control activities). Others 
suggested requiring design and construction features only where 
corrosive gas is transported. Others pointed to areas without a history 
of internal corrosion and suggested that the rule should not apply to 
pipelines installed in these areas.
    PHMSA does not agree with the suggestions of these commenters and, 
accordingly, is not establishing exceptions to design and construction 
requirements based on expected operations. An operator needs to include 
internal corrosion control measures in operation and maintenance 
programs. Relying on these operation and maintenance programs alone to 
control internal corrosion misses the safety and economic benefit from 
good design. Building features to reduce the risk of corrosion into new 
pipelines costs little and provides additional and fuller protection 
against internal corrosion. Even where operators do not expect to have 
liquids enter the pipeline, one commenter noted that an operator cannot 
rule out upset conditions which can result in the introduction of 
liquids. These can occur when there is an operational error; tertiary 
recovery introduces liquids; gas comes from a new or different area of 
the same field; gas from a different operator joins the gas stream; 
equipment fails; or other causes. The increased risk of internal 
corrosion such a situation causes, albeit possibly small, justifies the 
minimal incremental cost of incorporating the measures required in the 
final rule. However, in the interest of cost effectiveness, PHMSA 
agrees with the need to provide operators flexibility to select design 
and construction options fitting the relative risks that there will be 
liquids in the pipeline in the future.

Exceptions for Particular Types of Facilities

    A few commenters requested that PHMSA carve out exceptions to the 
final rule for particular types of pipeline facilities. We address 
these comments in the following paragraphs, by reference to the 
particular pipeline facilities in issue.
    Offshore pipelines. The Interstate Natural Gas Association of 
America and one large gas transmission operator requested that PHMSA 
carve out an exception for offshore lines. Among the reasons given were 
the lower risk to public safety in the offshore environment and the 
impossibility of engineering out the effects of dips and low spots 
offshore. PHMSA agrees that offshore lines should be excepted from the 
final rule.
    Although there have been serious gas incidents offshore, these have 
been caused by outside force damage sufficient to rupture the pipeline, 
such as an anchor dragging or vessel

[[Page 20057]]

grounding. This sort of damage includes sources of ignition from 
vessels passing overhead. In contrast, a corrosion leak in an offshore 
gas pipeline poses less risk to people. Unless corrosion is widespread, 
a corrosion failure is likely to leak rather than rupture and is not 
likely to pose a threat to people. It is highly unlikely that a vessel 
would pass over the underwater pipeline at the moment of rupture and 
provide both a source of ignition triggering a fire and people to be 
killed or injured. Between 2000 and 2005, there were more than twice as 
many internal corrosion incidents offshore as onshore, but less damage, 
even though damage includes the cost of lost gas and repair to the 
underwater pipeline. There have been no injuries or fatalities.\2\
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    \2\ The only fire was almost instantaneously extinguished by the 
water.
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    Finally, as noted by the commenters, there are more limited design 
and construction options available for offshore pipelines. Pipelines 
commonly follow the contours of the seabed with its natural low points. 
Installing and operating liquid removal equipment is not possible at 
low points in deep water. Some new pipelines are being installed in 
water more than one mile deep, complicating the under water pipeline 
design process. Control of liquids in the gas stream is already a 
critical factor in deep water pipeline construction and operation.
    Moreover, adopting this exception will not leave offshore pipelines 
unprotected or allow an operator to ignore the risk of internal 
corrosion. Existing regulations in subparts I and L require operators 
of offshore pipelines to address internal corrosion during operation 
and maintenance.
    Gathering lines. The only regulated gas gathering lines are those 
in populated areas, where the risk of injury or property damage in the 
event of failure is greatest. By their very nature, gathering lines 
regularly transport gas containing liquids--a combination known to 
cause corrosion over time. Approximately a third of onshore incidents 
caused by internal corrosion involve gathering lines.\3\ None of the 
commenters challenged these basic facts. PHMSA does not except 
gathering lines from this final rule.
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    \3\ Based on data reported for incidents occurring between 2000 
and 2005.
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    At least one commenter suggested that gathering lines were not 
within the scope of the NPRM in this rulemaking. That is not the case. 
When PHMSA issued the NPRM in December 2005, gas gathering lines in 
non-rural areas were subject to the same regulations applicable to 
transmission pipelines (49 CFR 192.9 (2005)). The only exceptions were 
the requirement that new pipelines accommodate internal inspection 
devices (Sec.  192.150) and integrity management regulations (subpart 
O). PHMSA published a Supplemental Notice of Proposed Rulemaking 
(SNPRM) proposing changes to regulation of gathering lines on October 
3, 2005 (70 FR 57536). The SNPRM on gathering lines proposed to 
continue to subject gathering lines to most regulations applicable to 
transmission pipelines, including both corrosion control and design and 
construction requirements. The final rule on gathering lines continued 
to subject gathering lines to corrosion control and design and 
construction requirements such as this final rule (71 FR 13289; March 
15, 2006).
    Compressor stations. PHMSA is not persuaded that the final rule 
should except compressor stations. The commenter suggesting an 
exception did not offer a reason, and we cannot discern one. 
Compressors do not operate well when liquids are present in the gas 
flow. Actions to remove liquid before it enters the compressor may 
result in liquid accumulation in the compressor station piping. About 
forty percent of the damage caused by internal corrosion onshore 
incidents between 2000 and 2005 was due to incidents at compressor 
stations. People work in compressor stations. They also live near 
compressor stations, particularly in suburban locations in which there 
has been significant development since the transmission pipelines were 
constructed.

Placement Within 49 CFR Part 192

    Several commenters suggest subpart I--Requirements for Corrosion 
Control--is the wrong place for a rule addressing internal corrosion 
control in design and construction. Commenters cite two reasons for 
their position. First, the regulations in subpart I primarily address 
operation and maintenance requirements. These requirements apply to 
pipelines existing when the regulations are issued. Design and 
construction requirements, such as those in the final rule, apply only 
to new and replaced pipelines. The commenters suggest PHMSA place these 
requirements applicable only to new and replaced pipelines in one of 
the subparts of 49 CFR part 192 which contain no requirements 
applicable to existing pipelines. Second, some commenters suggest that 
operators designing and constructing pipelines might overlook design 
and construction requirements placed in subpart I. Commenters who 
addressed the issue were not uniform in their suggestions for alternate 
placement within Part 192. They suggest placement in subpart C--Pipe 
Design, subpart D--Design of Pipeline Components, or subpart G--General 
Construction Requirements for Transmission Lines and Mains.
    Some regulations in subpart I already include design and 
construction requirements, such as requirements for pipe coating. PHMSA 
believes consolidating corrosion control requirements strengthens the 
planning aspects of this regulation. To address commenters' concerns, 
PHMSA has reworded the final rule to be consistent with other design 
and construction requirements in the regulations. We have also added an 
applicability date to the final rule clearly indicating the non-
retroactive effect of the design and construction requirements. 
Finally, the final rule cross references subpart I in subpart D to 
alert those designing pipelines of the need to consult corrosion 
control requirements.

Recordkeeping

    Many commenters and the TPSSC expressed concern about the 
recordkeeping provision proposed in the NPRM, contending it would be 
costly, difficult to adhere to, and burdensome. PHMSA agrees. Operators 
normally maintain as-built drawings and other construction records. 
These records may already contain adequate explanation of variances. If 
not, some additional explanation will be necessary. We have modified 
the final rule to require maintenance of records demonstrating 
compliance.

Changes Affecting Downstream Pipeline

    Few commenters discussed the proposal to require an operator to 
address the effect changes to an existing pipeline would have on the 
risk of internal corrosion in the downstream portions of the pipeline. 
The Texas Pipeline Association noted that the proposal matched what 
prudent operators already do and that the proposed standard was 
appropriate. Another commenter noted the proposed language might be too 
restrictive because it would require an operator to use equipment to 
address the effects. One member of the TPSSC noted that the proposal 
would apply to any change to the pipeline and suggested clarifying the 
regulation to apply only to changes affecting configuration. We have 
made changes to the final rule to limit applicability to changes that 
have the potential for affecting downstream risk. The final rule allows 
operator flexibility in addressing the risks.

[[Page 20058]]

Changes Due To Uprating

    Existing pipeline safety regulations (Sec.  192.555 and Sec.  
192.557) allow an operator to increase maximum allowable operating 
pressure of a gas pipeline through a process called uprating. Uprating 
results in operation at an increased hoop stress. A pipeline operating 
at a hoop stress of 20 percent or more of the specified minimum yield 
strength is considered a transmission pipeline by definition regardless 
of its function (Sec.  192.3). Thus, uprating a distribution line may 
result in its classification as a transmission line. A member of the 
TPSSC asked whether such a change would result in the line being 
considered a new transmission line subject to the design and 
construction requirements of this final rule. The answer is no. The 
uprated line is not newly constructed. However, to the extent an 
operator makes replacements in the line in connection with uprating to 
meet the requirements of Sec.  192.555(b)(2) or Sec.  192.557(b)(3), 
the replacements must be designed and constructed in accordance with 
this final rule. In addition, the operator would have to consider the 
effect of the replacement on internal corrosion risk to the downstream 
portion of the pipeline.

Terminology

    The proposed rule allows an operator to deviate from specific 
aspects of design and construction if the operator can demonstrate that 
compliance is ``impracticable'' or ``unnecessary.'' Some commenters 
said that the terms are too subjective and will result in disputes over 
the appropriateness of an operator's actions. They suggest 
clarification through examples. We do not agree that further 
clarification is required at this time. The terms ``impracticable'' and 
``unnecessary'' are used elsewhere in regulation. As long as an 
operator makes a reasonable effort to address internal corrosion in 
design and construction, the potential for disagreement is slight. At 
the request of the TPSSC, PHMSA intends to conduct a public workshop on 
implementation of this regulation. Part of the workshop could be 
devoted to developing examples of situations in which regulators and 
industry agree that compliance with the final rule would be 
presumptively impracticable or unnecessary.

The Final Rule

    The final rule adds a new subsection to Sec.  192.143 in Subpart 
D--Design of Pipeline Components. The new subsection cross-references 
the design and installation requirements specifically addressing 
corrosion control in Subpart I--Requirements for Corrosion Control.
    The final rule also adds a new section to subpart I. The new 
section, Sec.  192.476, requires an operator to address internal 
corrosion risk when designing and constructing a new gas transmission 
line or when replacing line pipe or components in a transmission line.
    Paragraph (a) addresses design and construction. It imposes a 
general performance requirement--that the design and construction of 
new and replaced pipelines include features to reduce the risk of 
internal corrosion. More specifically, the rule identifies three 
categories of corrosion control features that an operator must provide 
for unless doing so is impracticable or unnecessary: (1) Configuration 
to reduce the risk that liquids will collect in the line (paragraph 
(a)(1)); (2) effective liquid removal features (paragraph (a)(2)); and 
(3) ability to use corrosion monitoring devices in locations with 
significant potential for internal corrosion (paragraph (a)(3)).
    There are many design features that an operator can incorporate to 
address the requirements of paragraph (a). These include the following:
    <bullet> An operator can minimize dead ends and low areas;
    <bullet> An operator can minimize aerial crossings, since these can 
result in variation of temperature;
    <bullet> An operator can design for turbulent flow, in which the 
velocity at a given point varies erratically in magnitude and 
direction, to decrease the chance of liquids separating from the flow 
and accumulating;
    <bullet> An operator can design a pipeline to minimize entry of 
water and corrosive gases at receipt locations;
    <bullet> When corrosive gas is expected, an operator can provide 
slam valves to isolate systems;
    <bullet> An operator can apply coatings to interior walls to 
inhibit internal corrosion;
    <bullet> An operator can identify critical low spots and instrument 
the pipeline to monitor relevant operating conditions (temperature, 
pressure, velocity, dew point);
    <bullet> An operator can evaluate seasonal nature of delivery and 
capacity patterns and design to avoid no-or low-flow conditions;
    <bullet> An operator can include equipment to evaluate gas 
characteristics; and
    <bullet> An operator can include equipment to allow sampling at key 
areas, such as pig traps, isolated sections with no flow, dead ends, 
and river and road crossings.
    Further, design should allow the use of cleaning pigs.\4\
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    \4\ Section 192.150 requires an operator to design most new and 
replaced transmission pipeline to allow the use of instrumented 
internal inspection devices. The exceptions to Sec.  192.150 include 
certain lower risk gathering lines and lines too small in diameter 
to accommodate instrumented internal inspection devices. Although 
neither Sec.  192.150 nor this final rule expressly requires 
designing to allow the use of cleaning pigs, it is much easier to 
accommodate cleaning pigs than instrumented internal inspection 
devices.
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    Paragraph (b) provides exceptions to applicability. The design and 
construction requirements do not apply to pipeline installed or 
replacements made before the effective date of the regulation. They 
also do not apply to offshore pipelines.
    Paragraph (c) requires an operator to consider and address the 
impact of changes in the physical features of a pipeline on internal 
corrosion risks of an existing downstream pipeline. This will ensure 
that changes in configuration made after a pipeline begins operation do 
not inadvertently increase the risk of internal corrosion. An operator 
who finds an increased risk due to changes upstream might need to 
install liquid removal equipment. Alternatively, after analysis, an 
operator may decide operation and maintenance measures would adequately 
address the impact. In its investigation of the Carlsbad accident, the 
NTSB noted the impact of the addition of a pig receiver many years 
after original construction.\5\ This change in configuration allowed 
the liquids from pigging which were not caught in the receiver to flow 
downstream supposedly to be caught in the drip installed at the time of 
original construction to capture liquids before the low points near the 
river. The NTSB report notes that the pig receiver was added without 
also installing a separate storage leg or tank to collect the liquids 
from pigging. The NTSB also notes that partial clogging of the original 
drip, a maintenance issue, allowed liquids to bypass the drip and 
collect at the eventual rupture site.
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    \5\ NTSB Report PAR 03-01, pages 41-42.
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    Paragraph (d) requires an operator to maintain records 
demonstrating compliance. Written procedures supported by as-built 
drawings and other construction records ordinarily will satisfy this 
requirement. However, these records must adequately show why an action 
described in paragraph (a)(1), (a)(2), or (a)(3) is impracticable or 
unnecessary. For example, an operator might have a written design 
allowing pipe to be laid following the contour of the land. To avoid 
accumulation of liquid in the low spots, the design procedure might 
call for incorporating

[[Page 20059]]

design features to maintain gas velocity or to remove liquids. The 
actual construction records or as-built drawings would show what the 
operator actually did. Another example might be a construction record 
showing the use of a filter or separator at the gate station of a 
distribution pipeline. Regardless of the choices in recordkeeping an 
operator makes, the records must show circumstances justifying variance 
based on impracticability or lack of necessity. For example, if an 
operator does not provide features for effective liquid removal at low 
spots, the records must show why it is not necessary to do so.

Regulatory Analyses and Notices

Privacy Act Statement

    Anyone can search the electronic form of all comments received in 
response to any of our dockets by the name of the individual submitting 
the comment (or signing the comment, if submitted on behalf of an 
association, business, labor union, etc.). The Department of 
Transportation's complete Privacy Act Statement is published in the 
Federal Register on April 11, 2000 (65 FR 19477), and on the Web at 
http://dms.dot.gov.

Executive Order 12866 and DOT Policies and Procedures

    This final rule is not a significant regulatory action under 
section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was 
not subject to review by the Office of Management and Budget. This 
final rule is not significant under the Regulatory Policies and 
Procedures of the Department of Transportation (44 FR 11034).
    Commenters pointed to discrepancies in the incident data used for 
the regulatory evaluation. Those discrepancies have been corrected in 
the regulatory evaluation for this final rule. One member of the TPSSC 
questioned whether the analysis included consideration of 
uncertainties. We have considered the comment and decided that our 
analysis adequately handles uncertainty in benefits and costs.

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. This final 
rule would affect operators of gas transmission pipelines and onshore 
gas gathering pipelines. The number of small entities operating gas 
transmission pipelines is not substantial and the cost of compliance 
with the final rule is small. Therefore, I certify, under 5 U.S.C. 605, 
that this rulemaking will not have a significant impact on a 
substantial number of small entities.

Executive Order 13175

    PHMSA has analyzed this final rule according to Executive Order 
13175, ``Consultation and Coordination with Indian Tribal 
Governments.'' Because the final rule will 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.

Paperwork Reduction Act

    This final rule affects information collection that the Office of 
Management and Budget has approved under Control Number 2137-0049 
(recordkeeping under 49 CFR part 192). Operators of gas transmission 
pipelines must keep records to show the adequacy of corrosion control 
measures. In addition, they must keep construction records and make 
them available to individuals operating and maintaining the pipeline. 
The final rule may require some added effort to document decisions 
about internal corrosion made during design and construction. Because 
of existing recordkeeping needs and prudent business practice, PHMSA 
estimates the added burden hours will be nominal.

Unfunded Mandates Reform Act of 1995

    This final 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 to either State, local, or tribal governments, in 
the aggregate, or to the private sector, and is the least burdensome 
alternative that achieves the objective of the rulemaking.

National Environmental Policy Act

    PHMSA has analyzed the final rule for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the final 
rule requires limited physical change or other work that would disturb 
pipeline rights-of-way, PHMSA has determined the final rule is unlikely 
to affect the quality of the human environment significantly. An 
environmental assessment document is available for review in the 
docket.

Executive Order 13132

    PHMSA has analyzed the final rule according to Executive Order 
13132 (``Federalism''). The final 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 final rule 
does not impose substantial direct compliance costs on State and local 
governments. Federal pipeline safety law prohibits State safety 
regulation of interstate pipelines. This regulation would not preempt 
state law for intrastate pipelines. Therefore, the consultation and 
funding requirements of Executive Order 13132 do not apply.

Executive Order 13211

    Transporting gas impacts the nation's available energy supply. 
However, this final rule is not a ``significant energy action'' under 
Executive Order 13211. It also is not a significant regulatory action 
under Executive Order 12866 and is not likely to have a significant 
adverse effect on the supply, distribution, or use of energy. Further, 
the Administrator of the Office of Information and Regulatory Affairs 
has not identified this final rule as a significant energy action.

List of Subjects in 49 CFR Part 192

    Design and construction, Internal corrosion, Pipeline safety.

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

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

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

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


0
2. Amend Sec.  192.143 by designating existing text as paragraph (a) 
and adding a new paragraph (b) to read as follows:


Sec.  192.143  General requirements.

* * * * *
    (b) The design and installation of pipeline components and 
facilities must meet applicable requirements for corrosion control 
found in subpart I of this part.

0
3. Add Sec.  192.476 to read as follows:


Sec.  192.476  Internal corrosion control: Design and construction of 
transmission line.

    (a) Design and construction. Except as provided in paragraph (b) of 
this section, each new transmission line and each replacement of line 
pipe, valve, fitting, or other line component in a transmission line 
must have features incorporated into its design and construction to 
reduce the risk of

[[Page 20060]]

internal corrosion. At a minimum, unless it is impracticable or 
unnecessary to do so, each new transmission line or replacement of line 
pipe, valve, fitting, or other line component in a transmission line 
must:
    (1) Be configured to reduce the risk that liquids will collect in 
the line;
    (2) Have effective liquid removal features whenever the 
configuration would allow liquids to collect; and
    (3) Allow use of devices for monitoring internal corrosion at 
locations with significant potential for internal corrosion.
    (b) Exceptions to applicability. The design and construction 
requirements of paragraph (a) of this section do not apply to the 
following:
    (1) Offshore pipeline; and
    (2) Pipeline installed or line pipe, valve, fitting or other line 
component replaced before May 23, 2007.
    (c) Change to existing transmission line. When an operator changes 
the configuration of a transmission line, the operator must evaluate 
the impact of the change on internal corrosion risk to the downstream 
portion of an existing onshore transmission line and provide for 
removal of liquids and monitoring of internal corrosion as appropriate.
    (d) Records. An operator must maintain records demonstrating 
compliance with this section. Provided the records show why 
incorporating design features addressing paragraph (a)(1), (a)(2), or 
(a)(3) of this section is impracticable or unnecessary, an operator may 
fulfill this requirement through written procedures supported by as-
built drawings or other construction records.

    Issued in Washington, DC on April 16, 2007.
Thomas J. Barrett,
Administrator.
[FR Doc. E7-7701 Filed 4-20-07; 8:45 am]
BILLING CODE 4910-60-P


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