[Federal Register Volume 67, Number 9 (Monday, January 14, 2002)]
[Rules and Regulations]
[Pages 1650-1661]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-267]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Parts 195

[Docket No. RSPA-99-6355; Amendment 195-74]

RIN 2137-AD61


Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Repair Criteria)

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: This final rule finalizes repair provisions for hazardous 
liquid pipelines. These provisions were initially proposed in the 
previous rulemaking action which addressed requirements for pipeline 
integrity management programs in high consequence areas for operators 
owning or operating 500 or more miles of hazardous liquid or carbon 
dioxide pipeline (Integrity Management rule.) In the Integrity 
Management rule, we requested comment on the repair and mitigation 
provisions, because the provisions were substantially modified from 
those originally proposed in the notice of proposed rulemaking. This 
final rule also makes several non-substantive corrections and 
clarifications to other provisions of the Integrity Management rule.

DATES: This rule is effective May 29, 2001, except for paragraph (h) of 
Sec. 195.452 which takes effect February 13, 2002. The incorporation by 
reference of certain publications in this rule is approved by the 
Director of the Federal Register as of February 13, 2002.

FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, or by e-
mail: [email protected], regarding the remediation provisions in 
paragraph (h) or any other provisions of the integrity management rule; 
or the Dockets Facility (202) 366-9329, for copies of this final rule 
or other material in the docket. All materials in this docket may be 
accessed electronically at http://dms.dot.gov. General information 
about the RSPA/Office of Pipeline Safety (OPS) programs may be obtained 
by accessing OPS's Internet homepage at http://ops.dot.gov.

SUPPLEMENTARY INFORMATION:

Background

    On December 1, 2000, RSPA published a final rule (65 FR 75378) that 
prescribed integrity management

[[Page 1651]]

program requirements for pipeline operators who own or operate 500 or 
more miles of pipeline transporting hazardous liquids or carbon 
dioxide. Under the Integrity Management rule, operators are required to 
develop and implement integrity management programs that focus on 
hazardous liquid and carbon dioxide pipelines that could affect high 
consequence areas. High consequence areas are defined as: populated 
areas, areas unusually sensitive to environmental damage, and 
commercially navigable waterways.
    As part of the Integrity Management final rule, we requested 
comment on repair and mitigation provisions (Sec. 195.452(h).) We made 
this request because we substantially changed the initial provisions 
proposed in the notice of proposed rulemaking. We noted at that time 
that, at the end of the comment period (March 31, 2001), we would 
either publish a final rule modifying these repair provisions or 
stating that the provisions would remain unchanged. We received 
comments from six sources. Based on our analysis of the comments 
received, we modified paragraph (h). We discussed the comments, our 
responses, and changes made to these provisions below, in greater 
detail.
    This document also makes several corrections and language 
clarifications to other provisions in Sec. 195.452 and the Appendix C 
guidance. These changes do not affect the substance of any of the 
Integrity Management rule requirements. Rather, these revisions either 
correct the rule because of mistakes found since the rule was issued, 
or they clarify some of the language.

Corrections

    The reference in paragraph (j)(4)(i) that the external monitoring 
technology provide an understanding of the line pipe equivalent to that 
obtained under paragraph (j)(2), was incorrect. The reference should be 
to the assessment methods listed in paragraph (j)(5), not to the 
evaluation described in paragraph (j)(2).
    We deleted the sentence in paragraph (j)(4)(ii) requiring an 
operator to complete an integrity assessment within 180 days, after 
providing 180-days advance notice that it could not complete the five-
year continual integrity assessment because of unavailable technology. 
If we did not remove this requirement, an operator would have to 
complete the re-assessment within the five-year period. Thus, the 
exception for a longer assessment period would be illusory.
    We corrected the notification period in paragraph (j)(5)(iii), 
which required using alternative technology in the continual integrity 
assessment, from 60 days to 90 days. 90 days is consistent with the 
advance notice required for a baseline assessment that uses technology 
other than a hydrostatic test or an internal inspection tool.
    We added paragraph number 1 to precede the first sentence in 
paragraph (l).
    We corrected the grammar in several places in Appendix C.

Clarifications and Non-Substantive Revisions

    We added carbon dioxide pipelines to Sec. 195.452(a) to clarify 
that the integrity management program requirements for hazardous liquid 
pipelines to also apply to carbon dioxide pipelines regulated under 
Part 195.
    We clarified in paragraphs (c)(1)(i) and (j)(5) that the three 
allowable assessment methods for the baseline and continual integrity 
assessments are to be applied to lap welded pipe and to low frequency 
ERW pipe.
    We clarified that the periodic evaluation (paragraph (j)(2)) is to 
consider the results from the integrity assessments required by 
Sec. 195.452, i.e., the baseline and continual integrity assessments.
    We clarified the language in paragraph (j)(4)(i) regarding the 
justification and notice required for a variance based on engineering 
reasons.
    We added the requirement that an address and facsimile number must 
be included for notifications required by the Integrity Management 
rule, rather than referencing these in other pipeline safety 
regulations. Due to the confusion of some operators about where to send 
a notification required by Sec. 195.452 versus notifications required 
for other purposes, we added a new paragraph (paragraph (m)), which 
provides this information.
    We revised several paragraphs in Sec. 195.452 and Appendix C to 
make the terminology consistent with changes made to the terms used in 
paragraph (h).
    We added another section to the guidance in Appendix C, which lists 
conditions an operator should include in its schedule for evaluation 
and remediation.

Advisory Committee Consideration

    The Technical Hazardous Liquid Pipeline Safety Standards Committee 
(THLPSSC) is the Federal advisory committee charged with the 
responsibility of advising on the technical feasibility, 
reasonableness, cost-effectiveness, and practicability of proposed 
hazardous liquid pipeline safety standards. The committee is composed 
of members with the requisite statutory expertise who represent 
industry, government, and the general public.
    We discussed the repair provisions in paragraph (h) and comments 
received on those provisions by teleconference with the THLPSSC at its 
meeting on August 13, 2001. Before the discussion, the committee 
members were mailed a summary of comments on the repair provisions, and 
a supplement to the cost-benefit analysis that addressed these 
provisions.
    At the August 13 meeting, seven of the twelve current members 
participated in the teleconference. These seven THLPSSC members voted 
unanimously to accept the repair provisions, provided OPS consider the 
changes and comments discussed during the teleconference.
    The following is a list of the changes and comments that the 
THLPSSC asked OPS to consider:
     Reevaluate and relax the 60-day repair schedule for dents 
on the top of the pipe.
     Allow mitigative measures, other than repair.
     The provisions assume the use of in-line-inspection 
technology to identify defects although the rule allows both 
hydrostatic testing and other technologies for the integrity 
assessments.
     Provide that discovery of a defect occurs when an 
engineering analysis of the assessment results is completed.
     Let the section reflect that some internal inspection 
assessment results cannot be analyzed as quickly as others. For 
example, it typically takes a year following completion of the 
assessment to receive final results from a crack detection tool.
     Delete the section on other conditions requiring repair or 
move it to Appendix C as guidance material.
    We discuss below all changes made to Sec. 195.452(h) in response to 
the THLPSSC and other commenters.

Comments on Section 195.452(h)

    On December 1, 2000, OPS issued a final rule addressing pipeline 
integrity management in high consequence areas for operators owning or 
operating 500 or more miles of hazardous liquid or carbon dioxide 
pipeline (65 FR 75378) (The Integrity Management Rule.) This rule 
included provisions addressing the repair of conditions found during an 
integrity assessment. The provisions were found in paragraph (h) of 
section 195.452, under the title ``What actions must be taken to 
address integrity

[[Page 1652]]

issues.'' However, because the repair provisions in the Integrity 
Management rule were substantially different from what we initially 
proposed in the notice of proposed rulemaking, we requested comment on 
the provisions. All other provisions of the Integrity Management rule 
were final and became effective May 29, 2001.
    We received comments from the following six sources:

--One trade association with members affected by this rulemaking:
    American Petroleum Association (API)
--Three individual liquid pipeline operators:
    Tosco Corporation
    Chevron Pipe Line Company
    Colonial Pipeline Company
--One operator not directly affected by this rulemaking:
    Enron Transportation Services Company (natural gas transmission)
--One Engineering company:
    SEFBO Pipeline Bridge, Inc.

    SEFBO did not comment directly on the repair provisions but 
expressed its support for pipeline integrity management programs and 
stressed the importance of considering safety issues relating to the 
support structures used by pipelines to cross high consequence and 
other sensitive areas.
    Some of the comments we received about the repair provisions also 
addressed other portions of the final rule. As we only requested 
comment on the repair provisions in paragraph (h), this document will 
focus on those comments. If at some point we determine that substantive 
revisions to the final rule are necessary and we propose changes, we 
will then consider those comments.
    Comments on Section 195.452(h)--``What actions must be taken to 
address integrity issues?''
    1. General comments about paragraph (h):
    API objected to use of the word repair throughout paragraph (h). 
API contended the exclusive focus of the rule on repairs undermined the 
holistic approach of the rule. API commented that a key principle 
throughout the rule is the integration of information, so appropriate 
mitigative actions can be taken based on a comprehensive assessment. 
API explained that although actions may consist of repair, other 
actions such as further testing and evaluation, environmental changes, 
operational changes, or administrative changes could be appropriate. 
API advised that the goal should be to ensure operators differentiate 
defects injurious to a pipeline's integrity from those that are not.
    Tosco also commented that requiring repair in all instances was too 
inflexible, and operators must have the flexibility to address a wide 
range of conditions.
    Response:
    To assure the integrity of pipeline segments that could affect high 
consequence areas, Section 195.452 requires an operator to conduct a 
variety of assessments. The assessments include baseline and continual 
integrity assessments of the line pipe and periodic evaluations of 
entire pipeline systems, to assure the integrity of pipeline segments 
that could affect high consequence areas. This is accomplished through 
the continual identification and remediation of potential problems. We 
agree the word ``repair'' in paragraph (h) might be too narrow to 
encompass the range of actions an operator could take to address a 
problem. We intended paragraph (h) to reflect the broader actions an 
operator must take to address integrity issues that are identified. We 
further agree that all anomalies identified by an integrity assessment 
or information analysis might not require repair. Therefore, we 
replaced the word repair with remediate throughout paragraph (h). 
Remediate can encompass a broad range of actions, which include 
mitigative measures as well as repair, that an operator can take to 
resolve a potential integrity concern. Although we firmly believe 
repair is necessary to address many anomalies, we recognize repair may 
not be necessary in all instances. The rule provides the operator 
flexibility to determine the most appropriate action to take. However, 
we added language to ensure that whatever action is taken by an 
operator, it must be adequate to resolve the integrity concern on the 
pipeline for the long term. We also added a requirement that when an 
operator chooses to remediate a condition through a reduction in 
operating pressure, the pressure reduction is not to extend beyond 365 
days without the operator taking further action to ensure the safety of 
the pipeline.
    2. Section 195.452(h)(1)--General Requirements: In this paragraph 
we required an operator to take prompt action to address all pipeline 
integrity issues raised by the integrity assessment and information 
analysis, and evaluate all anomalies and repair those that could reduce 
a pipeline's integrity. An operator was further required to follow 
Sec. 195.422 in making a repair.
    API objected to the words ``prompt'' and ``all'' because these 
words could be interpreted in their absolute sense; could cause 
confusion because of the required time frames for addressing certain 
conditions; and could lead inspectors to require operators to take 
costly actions to address insignificant anomalies. API recommended 
deleting these terms.
    Tosco suggested the rule only require an operator to comply with 
Sec. 195.22 when a repair is necessary.
    Response:
    As explained in the previous section, we replaced ``repair'' with 
``remediate'' throughout paragraph (h), allowing for actions other than 
repair, in order to address integrity threatening pipeline conditions. 
This will allow an operator flexibility in how to address anomalous 
conditions on its pipeline.
    We did not delete the terms ``prompt'' and ``all.'' The pipeline 
safety regulations have long incorporated the term ``prompt,'' with 
consistent enforcement; there is little disagreement between operators 
and inspectors about its meaning. For the listed conditions, we 
determined what a prompt time frame should be (viz., immediate, 60 
days, 180 days), but leave it to the operator to determine appropriate 
time frames for other conditions. We kept the word ``all'' because it 
is a reasonable requirement for an operator to evaluate all conditions 
indicated by an integrity assessment or the information analysis, in 
order to determine the significance of each concern. Upon evaluation of 
the condition, the operator can then determine the appropriate further 
action to take, if any. We revised the language to clarify that an 
operator must evaluate all anomalous conditions (i.e., any condition 
that is irregular, abnormal, deviates from the norm, etc.) and 
remediate those conditions that could reduce the integrity of a 
pipeline.
    The word ``address'' is used in the introductory paragraph to 
encompass the process an operator should go through to find and remedy 
anomalous conditions, i.e., discovery, evaluation, and remediation of 
the condition through repair or other mitigative action. Using language 
to capture the process, is consistent with API's comment about the 
intended goal of the rule. By having an operator address all anomalous 
conditions raised by the integrity assessment or the information 
analysis, we envision a process that begins with discovery of a 
condition or anomaly that poses an integrity concern to the pipeline; 
continues with an evaluation that includes the analysis of other 
relevant data about the pipeline (this analysis could also be part of 
the discovery); and concludes with fixing the problem.
    We did not add ``if necessary,'' to the requirement about complying 
with

[[Page 1653]]

Sec. 195.422, as suggested by Tosco. The rule now uses the word 
remediate, which should alleviate any confusion about when compliance 
with Sec. 195.422 is necessary. Section 195.422 applies only to 
repairs. If actions other than repair are taken, the requirements in 
the section do not apply.
    3. Section 195.452(h)(2)--Discovery of a condition.
    The discovery of a condition triggers the time frames (either 
required by the rule or the operator's schedule) for remediating the 
condition. We defined discovery as occurring when an operator has 
adequate information to determine the need for a repair, and we 
provided examples of when such information might be available, 
depending on the circumstances. The examples included the receipt of 
the preliminary internal inspection report, the gathering and 
integrating of other inspection information, and the receipt of the 
final internal inspection report. The date of discovery could be no 
later than the date of the integrity assessment results or the final 
report.
    API objected to tying discovery to a specific point in time because 
discovery is not usually a single event but occurs over time as 
information is analyzed. API commented that other provisions of the 
Integrity Management rule require operators to integrate information 
from various sources, and tying the date of discovery to the date of 
the integrity results or receipt of the final report is inconsistent 
with the concept of integrating data. API maintained that too much 
emphasis is put on the use of internal inspection tools and the data 
collected from running these tools through a pipeline. API also 
commented that the emphasis on the results of in-line inspections in 
determining what action must be taken, is inappropriate and 
inconsistent with the rule's intent for information from multiple 
sources to be integrated in the assessment process. API suggested that 
rather than tying discovery to the integrity assessment results or 
final report, discovery should occur when an operator has integrated 
other inspections, tests, surveillance, controls, or pipeline integrity 
data with the final inspection report from an in-line inspection vendor 
or hydrostatic test. API believes this integration should be completed 
within 90 days from the receipt of the final inspection report.
    Tosco expressed similar concerns and suggested the word 
``discovery'' not be used, since it has the common meaning of when 
something is first found and might cause confusion with how the term is 
used in Sec. 195.56. Instead, Tosco would tie the repair schedules to 
the determination that a condition requires mitigation, which would be 
an outcome of the ongoing assessment process.
    Chevron also believed it is inappropriate to tie discovery to a 
specific event because discovery is a process that is subject to change 
with new information. Chevron suggested language changes identical to 
those recommended by API.
    Response:
    We contend that discovery triggers an operator's process to address 
a condition that could affect the integrity of a pipeline. Therefore, 
discovery has to occur at a specific point in time to start the period 
for evaluation and remediation of the condition. The use of the word 
``discovery'' here is consistent with how the word has been used in 
other pipeline safety regulation. However, to allow flexibility the 
rule provides that the time of discovery can vary depending on 
circumstances, and does not define discovery to occur at the same time 
for every operator and every pipeline.
    Discovery will depend on circumstances. We revised the rule to 
provide that discovery occurs when an operator has adequate information 
about a condition to determine the condition presents a potential 
threat to the integrity of the pipeline. The ``when'' for an operator 
to have sufficient information to make a determination will not be the 
same for every operator and every pipeline. Although the examples in 
paragraph (h) provide circumstances when discovery might occur, they 
were intended only as examples. We decided to eliminate the list as it 
is not exhaustive and may cause confusion. We did keep the performance-
based standard to give an operator flexibility when deciding there is 
adequate information to determine a condition presents a potential 
threat to its pipeline. However, we put an upper limit on the length of 
the discovery process. An operator must promptly obtain the information 
from an assessment to ensure that remediation of a condition which 
could threaten a pipeline's integrity occurs soon after an integrity 
assessment. The discovery process (the process for obtaining the 
adequate information) will end 180 days after an integrity assessment 
unless an operator can demonstrate that the 180-day period is 
impracticable.
    4. Section 195.452(h)(3)--Review of integrity assessment:
    This paragraph, as proposed, required an operator to include in its 
schedule for evaluation and repair a schedule for promptly reviewing 
and analyzing integrity assessment results. After March 31, 2004, an 
operator's schedule had to provide for this review within 120 days of 
conducting each assessment. The operator also had to obtain and assess 
a final report within an additional 90 days.
    API objected to setting a fixed period for the review of integrity 
assessment results. API commented that the language confused the role 
of the vendor who conducts a specific test or provides interpretive 
results, with the operator who conducts the integrity assessment and 
uses information from sources other than in-line inspections in 
performing those assessments. API explained that an operator contracts 
with the vendor for a specific service that is part of an overall 
integrity assessment.
    API also expressed concern that increased demand for inspection 
services would likely affect the time in which tool vendors deliver the 
reports. API stated that it is unlikely that operators will be able to 
meet the deadlines for every tool run and for every type of tool, as 
many types of tools are on the leading edge of development. API 
suggested that the rule: require review of integrity tests and 
inspections (rather than assessments); provide for integrating other 
appropriate data with the inspection/test results; and allow for a 
delay in schedule beyond the specified deadlines as long as an operator 
provides a reasonable explanation for the delay.
    Tosco commented that the two separate time periods is confusing; 
that if assessment of inspection results must be accomplished within 
120 days, it is not clear what additional evaluation is required within 
90 days of obtaining the report of an inspection.
    Response: We wish to note: an integrity assessment should not be 
confused with an integrity management program. Integrity management 
applies to the entire pipeline. It is a process that uses the 
information from an integrity assessment, in conjunction with the 
periodic evaluation and information analysis, to better manage the 
risks posed to each pipeline segment that could affect a high 
consequence area. Assessment is only one part of an operator's 
integrity management program and applies only to the line pipe. In the 
integrity management rule an assessment is required as a baseline and 
then required, periodically, every five years to ascertain the 
condition of the line pipe in each pipeline segment that could affect a 
high consequence area. To perform this assessment an operator has a 
choice of technologies: hydrostatic testing; internal inspection 
devices; or other technology. The rule clearly states that it is the 
operator's

[[Page 1654]]

responsibility to perform the required baseline and periodic 
assessments.
    Integration of information is a critical part of an operator's 
integrity management program. An operator must conduct periodic 
evaluations, which are to include evaluating data from the information 
analysis. The evaluations must be conducted as frequently as needed to 
assure pipeline integrity, not just when an assessment is done. Thus, 
the rule leaves it to each operator to best determine the frequency for 
evaluating its pipelines. We further expect an operator to structure 
its program to bring the necessary information together at the 
appropriate time.
    The requirement that an operator obtain and analyze an integrity 
assessment report by a specified time was intended to prompt an 
operator to obtain a timely report so that it could begin the repair of 
pipeline integrity-threatening conditions. However, after further 
analysis of this requirement we believe its implementation would be 
confusing and likely result in endless disagreements between operators 
and enforcement personnel. For example, an operator might have a 
condition on its pipeline that falls into the 60-day category. It could 
be argued that discovery occurred when the operator received a 
preliminary report of its integrity assessment, and that the operator 
was required to remediate the condition within 60 days after it 
received the report. However, the operator is supposed to have 120 days 
to review and analyze a preliminary report. Thus, there could be 
disagreement over whether the 60-day requirement negated the period for 
review and analysis, or whether the period for initial review and 
analysis gave the operator an additional 120 days before it was 
required to remediate the condition.
    Furthermore, we realized that the intent of this provision is to 
ensure an operator promptly addresses anomalous conditions on its 
pipeline, not to create disagreements about when an operator receives a 
report, reviews the report, and whether the report was a preliminary or 
final report.
    Rather than create a potential compliance and enforcement 
nightmare, we eliminated this provision from paragraph (h). Instead, we 
rewrote the provision (see discussion on discovery above) to give the 
operator flexibility in what information it uses, and what analysis it 
needs to discover a condition. Now an operator must promptly obtain 
sufficient information about a condition to make the determination that 
the condition presents a potential threat to the integrity of the 
pipeline. However, the obtaining of this information can take no longer 
than 180 days after an integrity assessment. 180 days after an 
integrity assessment, is considered sufficient time for an operator to 
obtain a report and any other information the operator needs to 
determine that a condition may present a threat. In limited instances, 
an operator may be able to demonstrate that the 180-day period is 
impracticable.
    By having a performance-based requirement, yet establishing an 
upper limit on when discovery can occur, it should be clearer to an 
operator on how to comply. It should also be clearer to determine when 
there is a violation, for enforcement purposes.
    The revised provisions ensure that an operator takes prompt action 
following an integrity assessment to remediate anomalous conditions and 
encourage operators to use sophisticated and developing technologies, 
because the operator will not be dependent on the report from the 
vendor.
    5. Section 195.452(h)(4)--Schedule for repairs: This paragraph 
required an operator to complete repairs according to a schedule that 
prioritizes conditions for evaluation and repair. The schedule was 
based on risk factors used for establishing the baseline and continual 
integrity assessment schedules. An operator would be allowed to notify 
RSPA/OPS when it could not meet the schedule and provide a 
justification for the delay. Notice was to be sent to the address in 
Sec. 195.58 or to the facsimile number in Sec. 195.56.
    API recommended the reference to the risk factors be deleted 
because the factors are appropriate for establishing re-inspection 
intervals but not for prioritizing mitigative actions.
    Tosco questioned, in the event an operator could not meet its 
schedule, whether the notification required should also be sent to the 
appropriate State agency in those States that are certified under 
Section 60105 of the Federal Pipeline Safety Statute. Tosco also noted 
that because Sec. 195.58 applies to subpart B and Sec. 195.56 applies 
to Safety Related Condition reports, we should reference the integrity 
management notification in these sections.
    Response:
    It is likely the results of an integrity assessment will be the 
principal basis for scheduling a condition for remediation. These 
results will generally indicate the significance of anomalies so 
operators can establish their relative importance for remediation. 
However, RSPA recognizes that there may be other factors an operator 
needs to consider in prioritizing the conditions for remediation, and 
agrees that requiring an operator to base its schedule on risk factors 
is unnecessary. We deleted this requirement from the rule and will 
leave it to the operator to determine how best to set up a schedule for 
evaluation and remediation of conditions identified from the 
assessment. Of course, an operator must document the basis for how it 
prioritizes conditions in its schedule.
    As for where an operator is to send a notification when it is 
unable to meet its schedule, the language clearly provides the address 
and facsimile numbers for sending the notification. Although we see no 
reason for confusion about where to send a notification, we added a new 
paragraph (m) to the integrity management rule that contains the 
address and facsimile number for sending notification. This paragraph 
now contains the current room number and facsimile number for sending 
any notification required by Sec. 195.452.
    The rule continues to require operator notification to RSPA/OPS. We 
will then ensure that the relevant Regional office receives the 
notification for forwarding to a certified State. Having the 
notification come to RSPA is consistent with the filing of other 
reports, such as the safety-related condition report and accident 
report. As RSPA plans to keep a data base of notifications, it is most 
practicable for it to be the notified agency rather than State safety 
agencies. It also prevents a burden to operators of trying to determine 
which agencies should be notified. Requiring all notifications under 
the Integrity Management rule first come to RSPA/OPS, eliminates any 
potential confusion about where a notification should be sent.
    When a certified State adopts the integrity management regulations, 
it may also add a requirement for notification by intrastate hazardous 
liquid operators.
    6. Section 195.452(h)(5)--Special requirements for scheduling 
repairs:
    This paragraph provided a list of certain conditions that require 
either immediate repair, repair within 60 days, or repair within six 
months. This paragraph also listed other conditions an operator would 
be required to evaluate and repair, but did not specify the time frame.
    Although not directly affected by this rulemaking, Enron maintained 
that the prescriptive time frames for certain conditions were not 
appropriate for the conditions, forcing operators to seek extensions. 
Enron further commented

[[Page 1655]]

that the descriptions of the conditions were open to interpretation.
    Immediate repair conditions: This subparagraph provided a list of 
conditions that require immediate repair. An operator is further 
required to temporarily reduce operating pressure or shut down the 
pipeline until the operator could complete the repair, basing the 
temporary operating pressure reduction on remaining wall thickness.
    API acknowledged that the conditions we listed as immediate repair 
conditions are those where the indicated anomaly may suggest the 
potential for imminent failure. However, API objected to limiting an 
operator's actions to address these conditions to repair of the 
condition. API recommended renaming these immediate concern conditions, 
and allowing an operator to take actions other than repair. API gave 
the example of a pipeline over-designed for wall thickness, as able to 
remain in service at very low pressure and not subject to imminent 
failure, even with metal loss greater than 80 percent of nominal wall 
thickness.
    API further stated that limiting an operator's discretion on 
reducing operating pressure to remaining wall thickness may be 
inappropriate in many situations (e.g., dents with indicated metal 
loss) and supported by engineering calculations. API suggested that the 
original wall thickness in some pipelines may have been above that 
needed to contain current maximum operating pressure, and recommended 
basing pressure reduction on an engineering assessment that includes 
all the potential factors that may contribute to pressure containment.
    Chevron recommended we remove the condition of ``dents on the top 
of the pipeline with any indicated metal loss'' from the immediate 
repair category. Chevron agreed such dents may be serious, but 
contended there is insufficient data to prove that these types of 
anomalies are of immediate concern. Chevron also believed an immediate 
repair requirement related to such anomalies would be difficult to meet 
because corrosion internal inspection tools do not always identify such 
dents, and those vendors that claim the tools can identify such dents 
cannot correctly size and identify them. Chevron recommended we place 
these types of anomalies in the 60-day category, and reword the anomaly 
description to include known topside dents that exceed 6 percent of the 
nominal pipe diameter with any (emphasis in the original comments) 
indicated metal wall loss. In addition, Chevron recommended RSPA work 
with industry to develop a pressure calculation that will determine the 
level of pressure reduction required (dependent on the size of the 
dent) to operate the pipeline safely.
    Response:
    We allowed an operator latitude in how it addresses most 
conditions, by changing the word repair to remediate throughout 
paragraph (h). However, we firmly believe that certain conditions, due 
to the immediate threat they pose to a pipeline's integrity and to a 
high consequence area, are best addressed by repair. We continue to 
list these conditions as ``Immediate repair conditions.'' An operator 
must repair these conditions; and until the repair is completed, either 
reduce operating pressure or shut down the pipeline.
    We agree that a situation might exist where an over designed pipe 
segment operating at a lower pressure could withstand maximum operating 
pressure, even with 80% wall loss. However, we find it unacceptable for 
an operator not to immediately repair a segment of pipeline where less 
than 20 percent of original wall thickness remains. Wall loss exceeding 
80% indicates something significant is occurring on the pipeline.
    We also do not agree with Chevron's suggestion that ``dents on top 
of the pipeline with indicated metal loss'' do not require immediate 
repair because they are hard to identify. We acknowledge current 
inspection techniques may not readily identify dents with metal loss. 
The rule does not require an operator to identify such conditions. The 
rule simply specifies that when such conditions are identified, an 
operator must repair them immediately. This type of dent is also 
classified as an immediate concern in the most recent draft of API-
1160, ``Managing System Integrity for Hazardous Liquid Pipelines.'' 
Therefore, we are not removing this condition from the list of 
immediate repair conditions.
    The reduction in operating pressure, or the shutdown of the 
pipeline, provides an additional margin of safety. This requirement is 
consistent with Sec. 195.401(b). This established regulation requires 
an operator to correct conditions that could adversely affect safe 
operations in a reasonable time and not operate the affected part of 
the system until the condition is corrected, if it is of such a nature 
that it presents an immediate hazard to persons or property.
    We agree that pressure reductions should be based on an engineering 
evaluation, and changed the final rule accordingly. Although it is 
appropriate to base the pressure reduction on the remaining wall 
thickness for corrosion, this may not be the best method on which to 
base a pressure reduction for dents and gouges. We modified the 
requirement so that an operator must calculate the temporary reduction 
in the operating pressure using the formula in section 451.7 of ASME/
ANSI B31.4.
    In response to concerns about the rule confusing the role of 
vendors with that of operators, we clarified the language in one of the 
listed conditions concerning the person responsible for making certain 
determinations about a condition. We revised the language so that now 
it is the person designated by the operator to evaluate assessment 
results, who is to determine whether an anomaly requires immediate 
action.
    60-day conditions:
    As proposed, this paragraph required an operator to schedule for 
evaluation and repair all dents (other than those listed as immediate 
repair conditions), regardless of size, located on the top of the 
pipeline (above the 4 and 8 o'clock position) within 60 days of 
discovery of the condition.
    API agreed with placing special emphasis on investigating anomalies 
that represent potential excavation damage on the top of the pipe. 
However, API contended that requiring repair of any topside dent, 
regardless of size, would preclude operators from making appropriate 
engineering judgments about anomalies that differ in character and risk 
profile from one pipeline to another.
    API contended that increasing sensitivities of inspection tools 
could result in ``hundreds or even thousands'' of topside line 
indications, only some of which will be a result of third-party damage. 
(Colonial and Chevron made the same comment). To better focus resources 
on areas of highest risk, API recommended we specify dents that are in 
excess of three percent of pipeline diameter and are located in a high 
population or other populated area, as 60-day conditions and include 
remaining dent-type defects as 6-month conditions. API believes this 
conservatively reduces by half the ASME B31.4 provisions, which require 
removal or repair of dents exceeding a depth of six percent of nominal 
diameter. API explained that the focus on high population areas and 
populated areas is appropriate because third-party activity is more 
likely to occur in these areas. (Chevron recommended these same 
changes). API further recommended excluding dents less than 0.25 inches 
for small diameter pipe (less than NPS 12) to recognize mill 
imperfections that fall within manufacturing tolerances. API maintained 
that operators have

[[Page 1656]]

conducted verification digs on many such small defects identified by 
past in-line inspections to demonstrate that these indications do not 
threaten pipeline integrity.
    Colonial reported in its experience, in-line inspection identified 
hundreds of bending shoe marks, smooth dents, and minor mill 
imperfections that fall within manufacturing tolerances. However, 
Colonial found these indications to be neither injurious to the 
pipeline nor the result of third-party damage. Colonial suggested that 
increased focus on these indications would result in dilution of 
resources and diversion of attention from higher risks. Colonial 
recommended we exclude ``smooth dents, bending anomalies, and mill 
defects that may be identified through engineering analysis and data 
integration including data gathered from previous excavations and 
inspections.''
    Chevron recommended we limit the 60-day conditions to known topside 
dents in excess of six percent of the nominal pipe diameter with any 
indicated metal loss, and that occur within a high population area or 
other populated area.
    Tosco would not limit the 60-day conditions to topside dents. Tosco 
explained that an operator must also evaluate dents located at the 
bottom of the pipe because they may indicate that the pipe has been 
damaged by lifting the line with excavation equipment.
    Response:
    Although commenters expressed concern about internal inspection 
tools not being able to detect immediate repair conditions, they also 
expressed concern about the tools finding too many of the 60-day 
conditions. We reconsidered what conditions an operator should address 
within 60 days from discovery. We decided to limit those conditions to 
large dents (i.e., those dents in excess of three percent of pipeline 
diameter) on the top of the pipeline and to dents on the bottom of the 
pipeline that contain stress concentrators because these types of dents 
are more likely to impair the integrity of the pipeline. We want the 
rule to encourage the use of more sophisticated inspection tools, as 
these tools become available. By modifying the list of 60-day 
conditions so that operators can better focus resources on remediating 
those conditions most likely to pose a threat to the integrity of a 
pipeline and to a high consequence area, operators will be encouraged 
to use more sensitive tools.
    We do not agree that the 60-day conditions should be limited to 
conditions found in high-population and populated areas. While it may 
be possible that third-party damage is more likely to occur in these 
areas, such damage can also occur in other areas. There is no reason 
why third party damage to a pipeline in an unusually sensitive 
environmental area should not be addressed as promptly as third party 
damage to a pipeline in another high consequence area. We make no 
distinction in the final rule between dents identified in populated 
areas and dents identified in other areas defined as high consequence.
    We did not make the change suggested by Tosco to include all dents 
located on the bottom of the pipe. We recognize that excavation damage 
limited to the bottom of pipe can occur, but understands it to be much 
less prevalent. However, we included under the 60-day conditions dents 
located on the bottom of the pipeline that have other indicators of 
damage, such as evidence of cracks or stress risers within the dent 
that would indicate a need for more immediate action. Significant dents 
(i.e., those dents with a depth greater than six percent of the pipe's 
diameter) on the bottom of pipe would require remediation within 180 
days of discovery. An operator must also evaluate and remediate any 
other dents on the bottom of the pipeline within a reasonable time.
    Six-month conditions: This paragraph listed several conditions an 
operator would have to schedule for evaluation and repair within six 
months following discovery.
    API recommended the list of 6-month conditions be completely 
rewritten and offered changes it believes use technically sound 
descriptions of the potential anomalies. API's revisions include the 
concept of minimum detection limits, particularly with respect to dent-
type anomalies. API claimed this would prevent the inappropriate 
diversion of safety resources that could result from a requirement to 
address ``all dents, regardless of size'' as detection capabilities 
increase. API echoed the comments of Colonial, discussed above, that 
in-line inspection companies have identified imperfections that fall 
within manufacturing tolerances and operators have conducted many 
verifying digs to demonstrate that these anomalies do not affect 
pipeline integrity. Colonial's comments in that regard are applicable 
also.
    Chevron also recommended a complete rewrite of the six-month 
conditions for the same reasons as API, and proposed language 
substantially the same as API's. Differences exist in addressing 
situations in which ``predicted burst pressure'' is less than 
established maximum operating pressure (API uses the term ``safe 
operating pressure''). API would limit the need to evaluate metal loss 
located at foreign pipeline crossings, to instances with greater than 
50 percent wall loss, while Chevron would address those with greater 
than 30 percent wall loss.
    Enron also commented that several of the listed conditions could 
require an expensive, time consuming, and non-productive diversion of 
safety resources. Enron believed evaluating dents with metal loss or 
dents affecting pipe curvature at a girth or seam weld, could result in 
numerous excavations. Many in-line inspection devices cannot identify 
such seams and having to investigate such dents, regardless of their 
depth, could require significant resources for little safety benefit. 
Enron raised the same concern regarding the need for unnecessary 
physical inspections to evaluate and repair corrosion of or along seam 
welds. Enron suggested that the six-month conditions only specify 
narrow axial external corrosion. Enron commented that the rule did not 
appear to allow pressure reduction as an option for addressing areas of 
general corrosion with predicted metal loss of greater than 50 percent 
of wall thickness.
    Response:
    To be consistent in language throughout paragraph (h), we now list 
the six-month conditions as 180-day conditions. We re-categorized some 
of the dents listed as 60-day conditions into the 180-day category 
because they are less severe. To avoid including minor and non 
integrity-threatening dents that fall within manufacturing tolerance 
limits, we revised the list of conditions to include dents greater than 
two percent of pipe diameter. The 180-day conditions category is 
consistent with the most recent draft of API-1160, ``Managing System 
Integrity for Hazardous Liquid Pipelines,'' except for minor 
differences. We included gouges and grooves greater than 12.5 percent 
of wall thickness, which are not in the API-1160 draft.
    Enron's concern regarding potential diversion of resources to 
address dents affecting seam welds was based on the perception that an 
operator would need to excavate most, or all dents to determine if they 
impacted a seam weld (similar logic underlies Enron's concern about the 
need to investigate corrosion along seam welds). We do not intend to 
require an excavation in order to identify the location of welds. We 
clarified the final rule to eliminate

[[Page 1657]]

confusion by setting de-minimus values for certain dents.
    We also clarified an apparent inconsistency in which we listed weld 
anomalies with predicted metal loss greater than 50 percent of wall 
thickness and corrosion of or along seam welds as 6-month conditions. 
We deleted from the list weld anomalies with a predicted metal loss 
greater than 50% of nominal wall. The rule now lists as 180-day 
conditions corrosion of and along a longitudinal seam weld, and metal 
loss greater than 50% that can affect a girth weld.
    Other conditions: Paragraph (h) also listed examples of other 
conditions an operator would need to schedule for evaluation and 
repair. API recommended we eliminate this paragraph as they contended 
it is unworkable and unenforceable. Many of the listed conditions, 
according to API, are not pipeline conditions but describe 
characteristics of the conditions as they might appear in raw 
inspection data. API argued that this paragraph oversimplifies the task 
of using past data in evaluations.
    Tosco also commented that the listed conditions seem to relate to 
an assessment using internal inspection tools, and conditions 
identified by other means of assessment (e.g., direct assessment) might 
not be addressed if this list were considered exhaustive.
    Enron commented that because the list of other conditions contain 
vague descriptions (e.g., over a large area, abrupt in nature, reflect 
a change, near casings), compliance with and enforcement of these 
requirements will be arbitrary, inconsistent and result in numerous 
disagreements between operators and regulators. As an example, Enron 
explained that a strict interpretation of the requirement requiring an 
operator to evaluate data that reflect changes since the last internal 
inspection, could include any change, no matter how small, or even one 
indicating an improvement. Enron argued for us to allow operators a 
reasonable degree of latitude in making decisions regarding what 
conditions must be evaluated, and requested we provide guidance in the 
rule on this latitude and not develop it through enforcement and 
interpretation. Finally, Enron maintained the repair requirements are 
likely to result in differing interpretations by different regulatory 
agencies.
    Response:
    The paragraph listing other conditions is not intended as an 
exhaustive list, but simply a list of some of the conditions an 
operator was to address in its schedule. We wrote paragraph (h), as 
well as other provisions of section 195.452, to include performance-
based and, when necessary, prescriptive language. The rule tries to 
balance the need of an operator for flexibility with the need for clear 
and enforceable regulations.
    Although we strive for clarity in a regulation, language is an 
imprecise instrument and is invariably subject to different 
interpretations. We face this challenge in every rulemaking, yet we 
enforce the regulations with a modicum of difficulty. Nonetheless, in 
response to the comments, we modified the list of other conditions to 
give better descriptions of certain conditions an operator should 
address, and we relocated the list to Appendix C. This list will now 
offer guidance to operators on conditions they should be prepared to 
evaluate and remediate. An operator will now be required to evaluate 
and remediate conditions other than those listed as immediate repair, 
60-day, and 180-day conditions, and in so doing to consider the 
guidance provided in Appendix C.
    Again, we want to emphasize that the conditions listed as immediate 
repair, 60 day, and 180-day are not an exclusive list of conditions an 
operator will be required to evaluate and remediate. These are simply 
some of the conditions that may show up. The argument that because a 
condition was not listed in paragraph (h) or in the Appendix C guidance 
and so an operator did not know it was required to evaluate and 
remediate the condition, will never be accepted.
    Comments on other provisions in the final rule:
    The Integrity Management Rule issued on December 1, 2000, was a 
final rule. We only sought comment on the repair provisions in 
paragraph (h) due to the substantive changes made from those initially 
proposed. All other provisions of the rule were previously subject to 
notice and comment. Therefore, we will not address comments aimed at 
other provisions in the rule, in this document.

Paragraph (h) Requirements

    Paragraph (h) of Sec. 195.452 requires an operator to take prompt 
action to address all anomalous conditions the operator discovers 
through the integrity assessment or information analysis. Addressing 
all conditions means an operator must evaluate all anomalous conditions 
and remediate those which could reduce a pipeline's integrity. The 
actions an operator may take to remediate a condition include a range 
of mitigative and other actions, including repair. However, the action 
taken must be adequate to ensure the condition is unlikely to present a 
long-term threat to the integrity of the pipeline.
    The time frames for evaluating and remediating certain conditions 
begin when the condition is discovered. Discovery of a condition occurs 
when an operator has adequate information to determine a condition 
presents a potential threat to the integrity of the pipeline. An 
operator must promptly, but no later than 180 days after an integrity 
assessment, obtain sufficient information about a condition to make the 
determination that a condition presents a potential threat to the 
integrity of the pipeline. Thus, an operator has flexibility 
determining when it has sufficient information for discovery. However, 
the discovery process will end 180 days after an integrity assessment, 
unless the operator can demonstrate that the 180-day period is 
impracticable.
    Discovery triggers the time frames for remediating a condition. An 
operator must have a schedule providing time frames for evaluating and 
completing remedial action on a condition.
    For most conditions, it is left to each operator to determine how 
to prioritize the conditions for evaluation and remediation. An 
operator must be able to justify its prioritization. The rule provides 
the time frames in which an operator must complete repair or 
remediation of certain conditions. These are listed as immediate repair 
conditions, 60-day conditions and 180-day conditions. Of course, the 
rule cannot identify all conditions an operator will have to evaluate 
and remediate. A condition an operator discovers may qualify as an 
immediate repair, 60-day or 180-day condition, even though it is not 
listed in the rule. The rule simply provides common examples of such 
conditions.
    The rule further provides that an operator is to include in its 
schedule, conditions other than those listed. Example of some 
conditions that could show up during an integrity assessment are 
provided in the Appendix C guidance. The list in the Appendix is not an 
exhaustive list.
    An operator may deviate from the scheduled time frames for 
remediation of a condition, if the operator justifies the reasons why 
it cannot meet the schedule and the changed schedule will not 
jeopardize public safety or environmental protection. An operator's 
justification for a deviation would be one of the records the operator 
is required to maintain for inspection. An operator must notify OPS if 
the operator cannot meet the schedule and cannot provide safety through 
a temporary

[[Page 1658]]

reduction in operating pressure. The operator would be required to 
provide RSPA/OPS notice by mail or facsimile.

Corrections to Section 195.452

    The rule allowed two limited exceptions for when an operator could 
seek a variance from the five-year re-assessment intervals. One 
exception (paragraph (j)(4)(i)) is if an operator can justify, on an 
engineering basis, for a longer assessment interval. Among other 
requirements, an operator is to support the justification with the use 
of other technology that provides an understanding of the line pipe 
equivalent to that provided by the other allowable assessment methods. 
However, instead of referencing the assessment methods listed in 
paragraph (j)(5), the rule incorrectly referenced (j)(2), the paragraph 
addressing the periodic evaluation. We corrected the reference.
    The second exception (paragraph (j)(4)(ii)) allows a variance 
because of unavailable sophisticated technology. For this exception an 
operator is to notify OPS 180 days before the end of the five-year 
interval. However, the rule further provided that an operator would 
then have to complete the assessment within 180 days. This requirement 
was incorrectly included and we deleted it. If an operator has to 
complete the re-assessment within 180 days of its 180-day notice, the 
operator would be completing the re-assessment within the five-year 
period. Therefore, with this requirement the exception allowing an 
extension is illusory. We deleted the requirement and instead, now 
specify that with its notice, an operator is to provide an estimate of 
when it will complete the re-assessment.
    Advance notice to OPS is required before an operator conducts a 
continual integrity assessment using alternative technology. Paragraph 
(j) (5) (iii) of the final rule gave this period as 60 days. This was 
incorrect. The advance notification period should be 90 days, to be 
consistent with the advance notification period required when an 
operator uses alternative technology for the baseline assessment. We 
corrected the time period.
    In paragraph (l), we inadvertently left out the number (1) before 
the first paragraph. We corrected this oversight.
    We also corrected the grammar in several places in the Appendix C 
guidance.

Clarifications and Non-Substantive Revisions to Section 195.452

    In paragraph (a) we clarified that the rule applies to any operator 
who owns or operates 500 or more miles of hazardous liquid or carbon 
dioxide pipeline. When we wrote the paragraph describing which 
operators need comply with the rule, we intended for the phrase 
``hazardous liquid'' to include carbon dioxide pipelines. However, we 
have since realized that because of how hazardous liquid and carbon 
dioxide are used in other pipeline safety regulations, there may be 
confusion about whether carbon dioxide lines are included. By changing 
the language to ``hazardous liquid or carbon dioxide,'' we eliminate 
any confusion about which operators are to comply.
    In paragraphs (c)(1)(i) and (j)(5), questions were raised about the 
listed methods an operator is allowed to use for an integrity 
assessment. The questions concerned the application of the methods to 
low frequency electric resistance welded pipe or lap welded pipe 
susceptible to longitudinal seam failure. We revised these paragraphs 
to make clear that the listed assessment methods apply to these types 
of pipe. Although for these types of pipe, an operator must choose 
methods that have certain capabilities, and the methods are to be from 
those listed in the rule.
    In paragraph (j)(2) we clarified that the evaluation of assessment 
results include results from the baseline or periodic integrity 
assessments. Although an operator may have performed a previous 
internal inspection, unless the operator uses that as its baseline 
assessment the operator would not have had to maintain those records 
because the pipeline safety regulations did not require an internal 
inspection. This clarification should avoid any disagreement about 
which integrity assessment records an operator will need for its 
periodic evaluations.
    In paragraph (j)(4)(i), we clarified the language about the 
requirements for the justification for a variance from the 5-year re-
assessment interval for engineering reasons and the requirements for 
notification to OPS.
    Due to changes we made to the terminology in paragraph (h), we 
revised several other paragraphs of the rule and Appendix C to be 
consistent with those changes. Affected paragraphs in Sec. 195.452 are 
(f)(4) and (j)(2), and in Appendix C, VI (16) and VI(18).
    We added a new paragraph (paragraph m) to the rule to clarify that 
the required notification must be sent to the Information Resources 
Manager, Office of Pipeline Safety, Research and Special Programs 
Administration, U.S. Department of Transportation, Room 7128, 400 
Seventh Street SW., Washington DC 20590, or to the facsimile number 
(202) 366-7128. Notification is required when an operator cannot meet 
its schedule for evaluating and remediating anomalous conditions; uses 
alternative technology for an integrity assessment; or seeks a variance 
from the five-year continual assessment interval.
    In Appendix C, which contains guidance material for Sec. 195.452, 
we added a section on conditions other than those listed in paragraph 
(h), which an operator could find from an integrity assessment and an 
operator should consider in its schedule for evaluation and 
remediation. We initially listed these conditions in paragraph (h) but 
decided they more appropriately fit into the Appendix C guidance. This 
guidance does not list every possible condition that could arise on a 
pipeline and an operator should evaluate. We also revised the 
introductory paragraph to reference the new section.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Regulatory Policies and Procedures

    This rulemaking action is not considered a significant regulatory 
action under section 3(f) of Executive Order (58 FR 51735: October 4, 
1993). Therefore, the Office of Management and Budget did not review 
this rulemaking document.
    We sought public comment on any additional financial burden that 
the repair requirements would have on the hazardous liquid pipeline 
industry. A supplemental report to the regulatory evaluation to address 
this issue is placed in the docket. The seven members present at the 
August 13, 2001, Technical Hazardous Pipeline Safety Standards 
committee meeting voted unanimously to accept the supplement to the 
regulatory evaluation. Below is a summary of their supplemental report.
Treatment of Repairs in Cost-Benefit Analysis for the Integrity 
Management Rule
    The final regulatory evaluation supporting the integrity management 
rule did not estimate the costs associated with repairs to pipe that 
may occur as a result of the rule. The evaluation instead focused on 
the costs associated with the planning and integrity assessments 
required by the rule. The reasons for not evaluating repair costs were:
    1. The pipeline safety regulations have always required an operator 
to repair problems found on its hazardous liquid or carbon dioxide 
pipelines. (49 CFR 195.401(b)). The primary changes made by the 
Integrity Management rule were to establish a systematized assessment 
and evaluation process that

[[Page 1659]]

would cause operators to better identify conditions on their pipelines 
requiring repair. Thus, the additional effort required of operators by 
the rule is in the planning and assessment process, the costs of which 
were considered in the regulatory evaluation. Repair of a problem, once 
it is known, was not a new requirement and was not evaluated because of 
the assumption that additional costs would not be incurred.
    2. The repair criteria in paragraph (h) of the final rule (65 FR 
75378; December 1, 2000) were changed from those published with the 
proposed rule. Accordingly, public comments were solicited regarding 
the repair criteria. RSPA received comments from six organizations (one 
trade association, one engineering company, three operators directly 
affected by the rule, and one operator not directly affected by the 
rulemaking). None commented on the lack of specific reference to repair 
costs in the regulatory evaluation.
    3. Some commenters identified criteria they believed would require 
unnecessary excavation and evaluation of minor pipeline anomalies that 
would not affect a pipeline's integrity. We made changes to the 
provisions in paragraph (h) in response to these comments. These 
changes clarify the types of conditions an operator must evaluate and 
remediate so the focus will be on those conditions that are most likely 
to affect pipeline integrity. Moreover, the remediation requirements 
allow an operator flexibility in the action it takes to address a 
condition that poses a threat to the integrity of its pipeline. These 
provisions are consistent with the existing requirements in section 
195.401(b), and add no additional costs.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), RSPA 
must consider whether a rulemaking would have a significant impact on a 
substantial number of small entities. This rulemaking was designed to 
impact only those operators that own or operate 500 or more miles of 
hazardous liquid or carbon dioxide pipeline. Because of this limitation 
on pipeline mileage, only 66 hazardous liquid pipeline operators (large 
national energy companies) covering 86.7% of regulated liquid 
transmission lines are impacted by this final rule. Based on this, and 
the evidence discussed above, I certify that paragraph (h) in the final 
rule addressing the remedial actions an operator is required to take to 
address integrity concerns on its pipeline will not have a significant 
impact on a substantial number of small entities.

Paperwork Reduction Act

    The pipeline integrity management rule contains information 
collection requirements. As required by the Paperwork Reduction Act of 
1995 (44 U.S.C. 3507 (d)), the Department of Transportation submitted a 
copy of the Paperwork Reduction Act Analysis to the Office of 
Management and Budget for its review. The information collection was 
reviewed and approved by the Office of Management and Budget. The name 
of the information collection is ``Pipeline Integrity Management in 
High Consequence Areas.'' The remediation requirements in paragraph (h) 
of the rule will not add any additional paperwork on hazardous liquid 
or carbon dioxide pipeline operators as repair requirements must 
already comply with 49 CFR 195.401(b). This was discussed above in the 
Regulatory Evaluation section. Therefore, no additional paperwork 
reduction analysis is necessary.

Executive Order 13084

    The remediation provisions of the integrity management final rule 
were analyzed in accordance with the principles and criteria contained 
in Executive Order 13084 (``Consultation and Coordination with Indian 
Tribal Governments.'') Because these provisions, as well as the other 
provisions of the final rule, do not significantly or uniquely affect 
the communities of the Indian tribal governments and do not impose 
substantial direct compliance costs, the funding and consultation 
requirements of Executive Order 13084 do not apply.

Executive Order 13132

    The final rule provisions in paragraph (h) were analyzed in 
accordance with the principles and criteria contained in Executive 
Order 13132 (``Federalism''). This final rule does not adopt any 
regulation that:
    (1) has substantial direct effects 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;
    (2) imposes substantial direct compliance costs on States and local 
governments; or
    (3) preempts state law.
    Nonetheless, State public safety representatives were involved 
throughout the development of the hazardous liquid integrity management 
rule.

Executive Order 13211

    This rulemaking is not a ``significant energy action'' within the 
meaning of Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use''). It 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, this rulemaking has not been 
designated by the Administrator of the Office of Information and 
Regulatory Affairs as a significant energy action.

Unfunded Mandates

    This 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 rule.

National Environmental Policy Act

    In accordance with section 102(2)(c) of the National Environmental 
Policy Act (42 U.S.C. Section 4332), the Council on Environmental 
Quality regulations (40 CFR Sections 1500-1508), and DOT Order 5610.1D, 
we prepared an Environmental Assessment (EA) that analyzed the 
environmental impacts of the rulemaking addressing integrity management 
programs for operators owning or operating 500 or more miles of 
hazardous liquid or carbon dioxide pipeline. In the EA we determined 
that the rule would not significantly affect the quality of the human 
environment. The EA and the Finding of No Significant Impact are 
available in Docket No. RSPA-00-6355. That EA considered the 
requirements in section 195.452 (h) concerning repairs an operator 
would have to make to its pipeline following an integrity assessment.
    We reviewed the EA in light of the changes we have made to 
Sec. 195.452 (h), and did not find that any of the changes affected our 
finding about the environmental impacts of the rule.

List of Subjects in 49 CFR Part 195

    Carbon dioxide, High consequence areas, Incorporation by reference, 
Integrity assurance, Petroleum, Pipeline safety, Reporting and 
recordkeeping requirements.


    For the reasons set forth in the Preamble, RSPA is amending part 
195 of title 49 of the Code of Federal Regulations as follows:

PART 195--[AMENDED]

    1. The authority citation for part 195 continues to read as 
follows:


[[Page 1660]]


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

Subpart F--Operation and Maintenance

* * * * *

Pipeline Integrity Management

    2. Section 195.452(a) is revised to read as follows:


Sec. 195.452  Pipeline integrity management in high consequence areas.

    (a) Which operators must comply?This section applies to each 
operator who owns or operates a total of 500 or more miles of hazardous 
liquid or carbon dioxide pipeline subject to this part.
* * * * *

    3. Section 195.452 is amended by revising paragraph (c)(1)(i) 
introductory text and paragraph (c)(1)(i)(C) to read as follows:
    (c) * * *
    (1) * * *
    (i) The methods selected to assess the integrity of the line pipe. 
An operator must assess the integrity of the line pipe by any of the 
following methods. The methods an operator selects to assess low 
frequency electric resistance welded pipe or lap welded pipe 
susceptible to longitudinal seam failure must be capable of assessing 
seam integrity and of detecting corrosion and deformation anomalies.
* * * * *
    (C) Other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify the Office of Pipeline Safety (OPS) 90 
days before conducting the assessment, by sending a notice to the 
address or facsimile number specified in paragraph (m) of this section.
* * * * *

    4. Section 195.452(f) (4) is revised to read as follows:
    (f) * * *
    (4) Criteria for remedial actions to address integrity issues 
raised by the assessment methods and information analysis (see 
paragraph (h) of this section);
* * * * *

    5. Section 195.452 (h) is revised to read as follows:
    (h) What actions must an operator take to address integrity issues?
    (1) General requirements. An operator must take prompt action to 
address all anomalous conditions that the operator discovers through 
the integrity assessment or information analysis. In addressing all 
conditions, an operator must evaluate all anomalous conditions and 
remediate those that could reduce a pipeline's integrity. An operator 
must be able to demonstrate that the remediation of the condition will 
ensure that the condition is unlikely to pose a threat to the long-term 
integrity of the pipeline. A reduction in operating pressure cannot 
exceed 365 days without an operator taking further remedial action to 
ensure the safety of the pipeline. An operator must comply with 
Sec. 195.422 when making a repair.
    (2) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about the condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after 
an integrity assessment, obtain sufficient information about a 
condition to make that determination, unless the operator can 
demonstrate that the 180-day period is impracticable.
    (3) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule that 
prioritizes the conditions for evaluation and remediation. If an 
operator cannot meet the schedule for any condition, the operator must 
justify the reasons why it cannot meet the schedule and that the 
changed schedule will not jeopardize public safety or environmental 
protection. An operator must notify OPS if the operator cannot meet the 
schedule and cannot provide safety through a temporary reduction in 
operating pressure. An operator must send the notice to the address 
specified in paragraph (m) of this section.
    (4) Special requirements for scheduling remediation.(i) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must provide for immediate repair conditions. To maintain safety, an 
operator must temporarily reduce operating pressure or shut down the 
pipeline until the operator completes the repair of these conditions. 
An operator must calculate the temporary reduction in operating 
pressure using the formula in section 451.7 of ASME/ANSI B31.4 
(incorportaed by reference, see Sec. 195.3). An operator must treat the 
following conditions as immediate repair conditions:
    (A) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (B) A calculation of the remaining strength of the pipe shows a 
predicted burst pressure less than the established maximum operating 
pressure at the location of the anomaly. Suitable remaining strength 
calculation methods include, but are not limited to, ASME/ANSI B31G 
(``Manual for Determining the Remaining Strength of Corroded 
Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3-805 
(``A Modified Criterion for Evaluating the Remaining Strength of 
Corroded Pipe'' (December 1989)). These documents are incorporated by 
reference and are available at the addresses listed in Sec. 195.3.
    (C) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) that has any indication of metal loss, cracking or a 
stress riser.
    (D) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) with a depth greater than 6% of the nominal pipe 
diameter.
    (E) An anomaly that in the judgment of the person designated by the 
operator to evaluate the assessment results requires immediate action.
    (ii) 60-day conditions. Except for conditions listed in paragraph 
(h)(4)(i) of this section, an operator must schedule evaluation and 
remediation of the following conditions within 60 days of discovery of 
condition.
    (A) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) with a depth greater than 3% of the pipeline 
diameter (greater than 0.250 inches in depth for a pipeline diameter 
less than Nominal Pipe Size (NPS) 12).
    (B) A dent located on the bottom of the pipeline that has any 
indication of metal loss, cracking or a stress riser.
    (iii) 180-day conditions. Except for conditions listed in paragraph 
(h)(4)(i) or (ii) of this section, an operator must schedule evaluation 
and remediation of the following within 180 days of discovery of the 
condition:
    (A) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or a longitudinal seam weld.
    (B) A dent located on the top of the pipeline (above 4 and 8 
o'clock position) with a depth greater than 2% of the pipeline's 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12).
    (C) A dent located on the bottom of the pipeline with a depth 
greater than 6% of the pipeline's diameter.
    (D) A calculation of the remaining strength of the pipe shows an 
operating pressure that is less than the current established maximum 
operating pressure at the location of the anomaly. Suitable remaining 
strength calculation methods include, but are not limited to, ASME/ANSI 
B31G (``Manual for Determining the Remaining Strength of

[[Page 1661]]

Corroded Pipelines'' (1991)) or AGA Pipeline Research Committee Project 
PR-3-805 (``A Modified Criterion for Evaluating the Remaining Strength 
of Corroded Pipe'' (December 1989)). These documents are incorporated 
by reference and are available at the addresses listed in Sec. 195.3.
    (E) An area of general corrosion with a predicted metal loss 
greater than 50% of nominal wall.
    (F) Predicted metal loss greater than 50% of nominal wall that is 
located at a crossing of another pipeline, or is in an area with 
widespread circumferential corrosion, or is in an area that could 
affect a girth weld.
    (G) A potential crack indication that when excavated is determined 
to be a crack.
    (H) Corrosion of or along a longitudinal seam weld.
    (I) A gouge or groove greater than 12.5% of nominal wall.
    (iv) Other conditions. In addition to the conditions listed in 
paragraphs (h)(4)(i) through (iii) of this section, an operator must 
evaluate any condition identified by an integrity assessment or 
information analysis that could impair the integrity of the pipeline, 
and as appropriate, schedule the condition for remediation. Appendix C 
of this part contains guidance concerning other conditions that an 
operator should evaluate.
* * * * *

    6. Sec. 195.452 is amended by revising the last sentence of 
paragraph (j)(2), revising paragraphs (j)(4), (j)(5) introductory text 
and (j)(5)(iii), and removing paragraph (j)(6)to read as follows:
    (j) * * *
    (2) Evaluation. * * * . The evaluation must consider the results of 
the baseline and periodic integrity assessments, information analysis 
(paragraph (g) of this section), and decisions about remediation, and 
preventive and mitigative actions (paragraphs (h) and (i) of this 
section).
    (3) * * *
    (4) Variance from the 5-year intervals in limited situations.(i) 
Engineering basis. An operator may be able to justify an engineering 
basis for a longer assessment interval on a segment of line pipe. The 
justification must be supported by a reliable engineering evaluation 
combined with the use of other technology, such as external monitoring 
technology, that provides an understanding of the condition of the line 
pipe equivalent to that which can be obtained from the assessment 
methods allowed in paragraph (j)(5) of this section. An operator must 
notify OPS 270 days before the end of the five-year (or less) interval 
of the justification for a longer interval, and propose an alternative 
interval. An operator must send the notice to the address specified in 
paragraph (m) of this section.
    (ii) Unavailable technology. An operator may require a longer 
assessment period for a segment of line pipe (for example, because 
sophisticated internal inspection technology is not available). An 
operator must justify the reasons why it cannot comply with the 
required assessment period and must also demonstrate the actions it is 
taking to evaluate the integrity of the pipeline segment in the 
interim. An operator must notify OPS 180 days before the end of the 
five-year (or less) interval that the operator may require a longer 
assessment interval, and provide an estimate of when the assessment can 
be completed. An operator must send a notice to the address specified 
in paragraph (m) of this section.
    (5) Assessment methods. An operator must assess the integrity of 
the line pipe by any of the following methods. The methods an operator 
selects to assess low frequency electric resistance welded pipe or lap 
welded pipe susceptible to longitudinal seam failure must be capable of 
assessing seam integrity and of detecting corrosion and deformation 
anomalies.
    (i) * * *
    (ii) * * *
    (iii) Other technology that the operator demonstrates can provide 
an equivalent understanding of the condition of the line pipe. An 
operator choosing this option must notify OPS 90 days before conducting 
the assessment, by sending a notice to the address or facsimile number 
specified in paragraph (m) of this section.

    7. Paragraph (k)(1) is redesignated as paragraph (l); paragraph 
designation ``(1)'' is added after the heading; and paragraph (k)(2) is 
redesignated as paragraph (l)(2).
* * * * *

    8. A new paragraph (m) is added to Sec. 195.452 to read as follows:
    (m) Where does an operator send a notification? An operator must 
send any notification required by this section to the Information 
Resources Manager, Office of Pipeline Safety, Research and Special 
Programs Administration, U.S. Department of Transportation, Room 7128, 
400 Seventh Street SW, Washington DC 20590, or to the facsimile number 
(202) 366-7128.

    9. Appendix C is amended by revising the title, adding paragraph 
(7) in the introductory text, revising paragraphs (7), (8), and (9) of 
section I.B., removing paragraph (18) from section VI and renumbering 
paragraphs (19) through (23) as (18) through (22), revising paragraphs 
(16) and newly designated (18) of section VI, and adding a new Section 
VII to read as follows:

APPENDIX C TO PART 195--GUIDANCE FOR IMPLEMENTATION OF AN INTEGRITY 
MANAGEMENT PROGRAM

* * * * *
    (7) Types of conditions that an integrity assessment may 
identify that an operator should include in its required schedule 
for evaluation and remediation.
    I. * * *
    B. * * *
    (7) Operating conditions of the pipeline (pressure, flow rate, 
etc.). Exposure of the pipeline to an operating pressure exceeding 
the established maximum operating pressure.
    (8) The hydraulic gradient of the pipeline.
    (9) The diameter of the pipeline, the potential release volume, 
and the distance between the isolation points.
* * * * *
    VI. * * *
    (16) integrity assessment results and anomalies found, process 
for evaluating and remediating anomalies, criteria for remedial 
actions and actions taken to evaluate and remediate the anomalies;
* * * * *
    (18) schedule for evaluation and remediation of anomalies, 
justification to support deviation from required remediation times;
* * * * *
    VII. Conditions that may impair a pipeline's integrity.
    Section 195.452(h) requires an operator to evaluate and 
remediate all pipeline integrity issues raised by the integrity 
assessment or information analysis. An operator must develop a 
schedule that prioritizes conditions discovered on the pipeline for 
evaluation and remediation. The following are some examples of 
conditions that an operator should schedule for evaluation and 
remediation.
    A. Any change since the previous assessment.
    B. Mechanical damage that is located on the top side of the 
pipe.
    C. An anomaly abrupt in nature.
    D. An anomaly longitudinal in orientation.
    E. An anomaly over a large area.
    F. An anomaly located in or near a casing, a crossing of another 
pipeline, or an area with suspect cathodic protection.

    Issued in Washington, DC, on December 21, 2001.
Ellen G. Engleman,
Administrator.
[FR Doc. 02-267 Filed 1-11-02; 8:45 am]
BILLING CODE 4910-60-P