[Federal Register Volume 65, Number 232 (Friday, December 1, 2000)]
[Rules and Regulations]
[Pages 75378-75411]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-29570]



[[Page 75377]]

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Part III





Department of Transportation





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Research and Special Programs Administration



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49 CFR Part 195



Pipeline Safety: Pipeline Integrity Management in High Consequence 
Areas (Hazardous Liquid Operators With 500 or More Miles of Pipeline); 
Final Rule

  Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / 
Rules and Regulations  

[[Page 75378]]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket No. RSPA-99-6355; Amendment 195-70]
RIN 2137-AD45


Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Hazardous Liquid Operators With 500 or More Miles of 
Pipeline)

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

ACTION: Final rule.

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SUMMARY: This final rule specifies regulations to assess, evaluate, 
repair and validate through comprehensive analysis the integrity of 
hazardous liquid pipeline segments that, in the event of a leak or 
failure, could affect populated areas, areas unusually sensitive to 
environmental damage and commercially navigable waterways. OPS is 
requiring that an operator develop and follow an integrity management 
program that provides for continually assessing the integrity of all 
pipeline segments that could affect these high consequence areas, 
through internal inspection, pressure testing, or other equally 
effective assessment means. The program must also provide for 
periodically evaluating the pipeline segments through comprehensive 
information analysis, remediating potential problems found through the 
assessment and evaluation, and ensuring additional protection to the 
segments and the high consequence areas through preventive and 
mitigative measures.
    Through this required program, hazardous liquid operators will 
comprehensively evaluate the entire range of threats to each pipeline 
segment's integrity by analyzing all available information about the 
pipeline segment and consequences of a failure on a high consequence 
area. This includes analyzing information on the potential for damage 
due to excavation; data gathered through the required integrity 
assessment; results of other inspections, tests, surveillance and 
patrols required by the pipeline safety regulations, including 
corrosion control monitoring and cathodic protection surveys; and 
information about how a failure could affect the high consequence area.
    The final rule requires an operator to take prompt action to 
address the integrity issues raised by the assessment and analysis. 
This means an operator must evaluate all defects and repair those could 
reduce a pipeline's integrity. An operator must develop a schedule that 
prioritizes the defects for evaluation and repair, including time 
frames for promptly reviewing and analyzing the integrity assessment 
results and completing the repairs. An operator must also provide 
additional protection for these pipeline segments through other 
remedial actions, and preventive and mitigative measures.

DATES: Effective Date: This final rule takes effect March 31, 2001.
    Compliance Dates: An operator must complete an identification of 
all pipeline segments that could affect a high consequence area no 
later than December 31, 2001. An operator must develop a written 
integrity management program no later than March 31, 2002.
    Comment Date: Interested persons are invited to submit comment on 
the provisions of the rule concerning actions an operator must take to 
address integrity issues on the pipeline (Sec. 195.452(h)) by March 31, 
2001. At the end of the comment period, we will publish a document 
modifying these remedial action provisions or a document stating that 
the provisions will remain unchanged.

ADDRESSES: Comments limited to the provisions on actions an operator 
must take to address pipeline integrity issues (Sec. 195.452(h)) must 
be sent to the Dockets Facility, U.S. Department of Transportation, 
Room PL-401, 400 Seventh Street, SW, Washington, DC 20590-0001. It is 
open from 10:00 a.m. to 5:00 p.m., Monday through Friday, except 
federal holidays. You also may submit written comments to the docket 
electronically. To do so, log on to the following Internet Web address: 
http://dms.dot.gov. Click on ``Help & Information'' for instructions on 
how to file a document electronically. All written comments should 
identify the docket number stated in the heading of this rule.

FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, or by e-
mail: [email protected], regarding the subject matter of this 
final 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 programs may be 
obtained by accessing OPS's Internet home page at http://ops.dot.gov.

SUPPLEMENTARY INFORMATION:  

Background

Notice of Proposed Rulemaking

    On April 24, 2000, OPS published a notice of proposed rulemaking 
(65 FR 21695) that proposed pipeline integrity management program 
requirements for hazardous liquid operators that operated 500 or more 
miles of pipeline. The proposed requirements were to apply to hazardous 
liquid pipelines that could affect areas we proposed as high 
consequence areas--populated areas, areas unusually sensitive to 
environmental damage, and commercially navigable waterways.
    OPS issued the proposal after a public meeting that OPS hosted on 
November 18 & 19, 1999, to gather information on current pipeline 
assessment methods and integrity management programs. OPS had also 
established an electronic public discussion forum to gather further 
information. Comments and information gathered from these forums were 
used in developing the proposed rule for larger hazardous liquid 
operations. The proposed rule was the first in a series of rulemakings 
that will require all regulated pipeline operators to have integrity 
management programs.
    The notice proposed that a hazardous liquid operator develop and 
follow an integrity management program. Among the proposed required 
elements of a program were--
     Baseline assessment of all pipelines that could affect a 
high consequence area. The integrity of these pipelines was to be 
assessed by internal inspection, pressure test, or equivalent 
alternative new technology. The assessment had to be completed in seven 
years, with 50% of the pipeline mileage done in three and one-half 
years.
     Continual assessment of all pipelines that could affect a 
high consequence area. An operator would have to continue to assess, at 
intervals not to exceed ten-years, and periodically evaluate the 
integrity of the pipelines.
     Data integration. An operator would have to integrate all 
information about the pipeline from diverse sources to analyze the 
entire range of threats to a pipeline's integrity.
     Prompt remedial action. An operator would have to take 
prompt action to address all integrity issues raised by the integrity 
assessment and data integration analysis.
     Preventive and mitigative measures. An operator would have 
to evaluate the need for additional measures to prevent and mitigate 
pipeline failures, such as installing emergency flow restricting 
devices (EFRDs) and establishing or

[[Page 75379]]

modifying systems that monitor pressure and detect leaks.
     Performance measures to measure the effectiveness of the 
program.
    The proposed rule permitted two options in establishing baseline 
and continual assessment schedules. An operator choosing the first 
option would have to base the schedule on specified risk factors. With 
the second option, an operator would base the schedule on risk factors 
the operator considered essential in risk or consequence evaluation.
    The NPRM explained in great detail the background of the proposed 
rule for the integrity management program (65 FR 21695; April 24, 
2000).
    In the NPRM, we said that we intended to apply integrity management 
program requirements to all regulated pipeline operators but that we 
would implement the requirements in several steps; when we were done, 
all regulated operators would be required to have an integrity 
management program. We explained that because natural gas and hazardous 
liquid have different physical properties, pose different risks, and 
the configuration of the systems differ, and because we needed to 
gather more information about smaller liquid operations, we were 
beginning the series of integrity management program proposals with 
hazardous liquid operators operating 500 or more miles of pipeline. We 
further stated that proposed regulatory requirements for the other 
operators would soon follow.
    The proposed rulemaking was the culmination of experience gained 
from inspections, accident investigations and risk management and 
system integrity initiatives. This experience was the foundation for 
proposing a rulemaking that addressed in a comprehensive manner NTSB 
recommendations, Congressional mandates and pipeline safety and 
environmental issues raised over the years. To recap the history of the 
rulemaking--
     The rulemaking addressed several recommendations NTSB made 
to OPS concerning pipeline safety.
    (1) Require periodic testing and inspection to identify corrosion 
and other time-dependent damages.
    (2) Establish criteria to determine appropriate intervals for 
inspections and tests, including safe service intervals between 
pressure testing.
    (3) Determine hazards to public safety from electric resistance 
welded (ERW) pipe and establish standards for leak detection, and 
expedite requirements for installing automatic or remote-operated 
mainline valves on high-pressure lines in urban and environmentally 
sensitive areas to provide for rapid shutdown of failed pipeline 
segments.
     Our analyses of several pipeline ruptures in Bellingham, 
Washington; Simpsonville, South Carolina; Reston, Virginia; and Edison, 
New Jersey, brought to light the need for operators to address the 
potential interrelationship among failure causes and to implement 
coordinated risk control actions to supplement the protection of the 
regulations.
     The rulemaking also addressed several Congressional 
mandates to OPS concerning areas where the risk of a pipeline spill 
could have significant impact.
    (1) 49 U.S.C. 60109(a)--prescribe standards establishing criteria 
for identifying gas pipeline facilities located in high-density 
population areas and for hazardous liquid pipelines that cross waters 
where a substantial likelihood of commercial navigation exists, or are 
located in a high-density population area, or are located in an area 
unusually sensitive to environmental damage (USAs).
    (2) 49 U.S.C. 60102(f)(2)--prescribe, if necessary, additional 
standards requiring the periodic inspection of pipelines in USAs and 
high-density population areas, and those crossing commercially 
navigable waterways, to include any circumstances when an instrumented 
internal inspection device, or similarly effective inspection method, 
should be used to inspect the pipeline.
    (3) 49 U.S.C. 60102(j)--survey and assess the effectiveness of 
emergency flow restricting devices (EFRDs) and other procedures, 
systems, and equipment used to detect and locate hazardous liquid 
pipeline ruptures, and to prescribe standards on the circumstances 
where an operator of a hazardous liquid pipeline facility must use an 
EFRD or such other procedure, system, or equipment.

Risk Management and Inspection Initiatives

    The proposed rulemaking was also based on what we had learned about 
integrity management programs from our risk management and pipeline 
inspection activities, particularly the Risk Management Demonstration 
Program, the Systems Integrity Inspection (SII) Pilot Program and the 
new high impact format for inspections. (These programs and activities 
are discussed in greater detail in the NPRM (65 FR 21695).)
    In the Risk Management Demonstration and Systems Integrity 
Inspection Pilot Programs, we studied and evaluated comprehensive and 
integrated approaches to safety and environmental protection. These 
approaches incorporated operator- and pipeline-specific information and 
data to identify, assess, and address pipeline risks, in conjunction 
with compliance with existing pipeline safety regulations. From these 
programs, we also learned about the extent and variety of internal 
inspection and other diagnostic tools that hazardous liquid pipeline 
operators use in their integrity management programs.
    OPS implemented a systems approach through a new high impact 
inspection format that evaluates pipeline systems as a whole rather 
than in small segments. We found that a system-wide approach is a more 
effective and, in most cases, more efficient means of evaluating 
pipeline integrity. As part of this approach, we have been evaluating 
how pipeline operators integrate information about their pipelines to 
determine the best means of addressing risk. This experience is helping 
us to develop detailed inspection guidelines to evaluate compliance 
with the requirements of this rule.

Advisory Committee Consideration

    The Technical Hazardous Liquid Pipeline Safety Standards Committee 
(THLPSSC) is the Federal advisory committee charged with responsibility 
for advising on the technical feasibility, reasonableness, cost-
effectiveness, and practicability of proposed hazardous liquid pipeline 
safety standards. The 15 member committee has balanced membership with 
individuals having the requisite expertise who represent industry, 
government, and the general public.
    We presented the proposed rule to the Technical Hazardous Liquid 
Pipeline Safety Standards Committee at its meeting on May 4, 2000. At 
the request of various committee members, who believed that they had 
not had sufficient time to review the proposed rule, which was 
published in April, 2000, formal consideration of the proposal was 
postponed to September. In preparation for this consideration, the 
draft cost-benefit analysis was mailed to the members on June 16, 2000 
and the members were briefed on the proposed rule in a teleconference 
on August 24, 2000.
    The committee began consideration of the proposed rule at a 
September 11, 2000 meeting (by teleconference) and completed 
consideration at a September 22, 2000 meeting (by teleconference). At 
the September 22 meeting, ten of the eleven participating THLPSSC 
members voted to accept the proposed rule provided several changes were 
made.

[[Page 75380]]

One member abstained from the general vote, but voted on the individual 
changes. These changes as well as other comments including minority 
views are described below. A more complete description can be found in 
the transcript of the committee's consideration of the proposed rule 
which is available in the docket.
    Various committee members had earlier expressed concern about the 
quality of the cost-benefit analysis. Concerns expressed included the 
lack of clear articulation of the benefits and the failure to follow 
the framework for cost-benefit analysis developed for use in pipeline 
safety rulemaking. In response to these concerns, OPS committed to 
revise the cost-benefit analysis to be more consistent with the 
framework prior to publication of a final rule. Discussion of the issue 
at the September 22nd meeting indicated that members did not want to 
delay the issuance of a final rule, but that they believed that the 
quality of the cost-benefit analysis to be important. The committee 
voted unanimously that it could not conclude that the proposed rule is 
reasonable at this time until OPS completed a more meaningful cost-
benefit analysis based on the framework. The committee recommended that 
this be done prior to issuance of the final rule.
    In addition, the committee unanimously made the following 
recommendations for changes to the proposed rule:
     Add pipeline stress to the list of risk factors to be 
considered in determining the frequency of integrity assessment.
     Clarify OPS's responsibility to identify, generate, 
publish, and update maps of high consequence areas.
     Establish time requirements for completion of repairs 
following detection of the defects. The timing may be tiered.
     Require leak detection capability.
     Specify the date (for example, January 1995) for 
acceptability of data from previously conducted internal inspections. 
This date should be consistent with the proposed 5 year look-back.
    With the exception of item 2 (responsibility for maps), RSPA has 
made changes to the final rule that address each of these 
recommendations. RSPA is addressing item 2 in this preamble, under the 
topic heading ``Definition of High Consequence Areas--Identification'', 
rather than in language of the rule. That section describes the process 
through which RSPA intends to make maps identifying high consequence 
areas available to the operators and the public.
    In addition to the formal recommendations of the committee, 
individual committee members raised two issues about which there was 
general agreement. The first of these concerned the need to clarify the 
applicability of the rule to offshore areas. This issue is addressed 
under the topic heading ``Applicability (Coverage) of the Rule.'' The 
second of these was the need to clarify the use of internal inspection 
to assess the integrity of pre-1970 electric resistance welded (ERW) 
pipe. The committee member was concerned that a footnote in the 
proposed rule would preclude internal inspection of this type of pipe. 
Accordingly, RSPA has modified the rule to address the issue. We 
discuss the rule modification later under the topic heading ``Program 
Implementation and Integrity Assessment Time Frames, Assessment Methods 
and Criteria.''
    Prior to the meeting, one committee member had raised the issue of 
requirements for emergency flow restricting devices. RSPA had indicated 
that it was considering including criteria for requiring the use of 
such devices. After a brief discussion in the meeting, the member 
decided not to pursue a formal recommendation by the committee. As 
discussed later in the Preamble under the topic heading ``Requirements 
for Preventive and Mitigative Measures, including, Emergency Flow 
Restricting Devices (EFRDs) and Leak Detection Devices'', RSPA has 
modified the rule's provisions concerning emergency flow restricting 
devices.
    There was some discussion in the various meetings that indicated 
some concern about how RSPA would be able to enforce broad requirements 
for programs. Some committee members suggested the need for specific 
criteria that inspectors could apply in reviewing an operator's 
program. Although these discussions did not result in formal 
recommendations by the committee, RSPA has included additional 
specificity in the final rule that will aid in reviewing integrity 
management programs. In addition, enforceability is discussed elsewhere 
in this preamble.
    The committee also discussed three other issues about which there 
was not general agreement. Four members of the committee believed that 
the final rule or a future modification should require leak detection 
systems and specify performance standards for those systems. The 
proposed rule did not propose to require or set standards for leak 
detection systems. (Current regulations require computational pipeline 
monitoring leak detection systems to comply with API 1130, the industry 
consensus standard.) Industry members raised concerns about the scope 
of the current proposed rule and offered to brief the committee at a 
future meeting on the range of leak detection systems currently 
available. As noted above, the committee finally recommended by 
unanimous consent that the final rule require that pipelines affecting 
high consequence areas have the capability of detecting leaks. As 
explained later in the Preamble under the topic heading ``Requirements 
for Preventive and Mitigative Measures, including, Emergency Flow 
Restricting Devices (EFRDs) and Leak Detection Devices'', we have 
revised the rule to address this recommendation.
    A second area of discussion about which there was not agreement was 
a motion to reduce the time for completion of the initial baseline 
assessment from seven years to three years. RSPA's rationale for not 
reducing this time frame is discussed elsewhere in this preamble.
    The third area was a motion to reduce the time interval for 
subsequent assessments from ten years to five years. The committee was 
evenly divided on this issue. As discussed elsewhere in this document 
under the heading ``Program Implementation and Integrity Assessment 
Time Frames, Assessment Methods and Criteria'', RSPA has decided to 
modify the time interval for integrity re-assessments subsequent to the 
baseline assessment.

Comments to NPRM

    We received comments from 36 sources in response to the NPRM:
2 Trade associations with members affected by this rulemaking
    American Petroleum Institute (API)
    American Water Works Association (AWWA)
3 Trade associations with members not directly affected by this 
rulemaking
    American Gas Association (AGA)
    New York Gas Group
    Interstate National Gas Association of America (INGAA)
8 Individual liquid operators
    Tosco Corporation
    Chevron Pipe Line Company
    BP Amoco
    Colonial Pipeline Company
    Koch Pipeline Company
    Equilon Pipeline Company
    Enbridge (U.S.) Inc. and Lakehead Pipe Line Partners
    Dynegy Midstream Services
4 Operators not directly affected by this rulemaking
    The Peoples Gas Light and Coke Company (LDC and intrastate)

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    Tennessee Gas Company (natural gas transmission)
    Enron Pipeline Group(natural gas transmission)
    Consumers Energy (natural gas transmission and distribution)
2 State agencies
    Lower Colorado River Authority (LCRA)
    State of Missouri--Department of Natural Resources
6 Advocacy groups
    Robert B. Rackleff, Friends of the Aquifer
    Pipeline Survivor's(sic) Association
    Environmental Defense
    National Pipeline Reform Coalition
    Fuel Safe Washington
    Harry S. Kottke and Delbert L. Moine, representing Ohio 
Pennsylvania Landowners Association (OPLA)
4 Federal agencies
    Environmental Protection Agency, Region III
    Environmental Protection Agency, Oil Program Center
    Department of Energy
    National Transportation Safety Board
2 Cities
    Austin, Texas
    Bellingham, Washington
3 Consultants/Contractors
    Batten and Associates
    Dr. Neb I. Uzelac
    SEFBO
2 Individuals
    U.S. Senator John Breaux
    Dene Miller Alden
General Comments
    Virtually all commenters were supportive of the need for additional 
and stronger regulations in this area, and provided comments and 
suggestions focusing on specific details and language of the proposed 
rule. Commenters generally fell into one of two groups: those that 
thought the general structure of the proposed rule was adequate and 
provided the appropriate balance between prescriptive requirements and 
pipeline-specific analysis, and those that believed the proposed rule 
was not sufficiently strong, broad enough in scope, or specific.
    All commenters were positive about the need for additional 
communication among industry, public safety officials, regulators, and 
the public concerning pipeline risks. We have decided to address the 
topic of public communication and interaction in a subsequent related 
rulemaking. We will address these comments in more detail in that 
rulemaking.
    The trade associations and operators that are not directly affected 
by this rulemaking provided comments in anticipation of future 
integrity management program regulations that would affect them. We 
will use these comments when preparing the proposed rulemakings for the 
other operators.
    We have summarized the comments we received under the following 
topic areas:

1. Clarity and Specificity in the Proposed Rule
2. Remedial Actions
3. Review, Approval, and Enforcement Processes
4. Program Implementation and Integrity Assessment Time Frames, 
Assessment Methods and Criteria
5. Applicability (Coverage) of the Rule
6. Consensus Standard on Pipeline Integrity
7. Definition of High Consequence Areas
8. Requirements for Preventive and Mitigative Measures, including, 
Emergency Flow Restricting Devices (EFRDs) and Leak Detection Devices
9. Methods to Measure Program Effectiveness
10. Cost Benefit Analysis
11. Information for Local Officials and the Public
12. Appendix C Guidance

    In addition, there were a variety of technical comments and 
suggestions concerning specific details of proposed Appendix C, and 
other technical language in the proposed rule. We did not include 
discussion of these detailed technical comments here but we did 
consider them in preparing the final rule and revising the Appendix.
    RSPA personnel also had numerous discussions with representatives 
from several federal government agencies during this rulemaking to 
resolve issues the agencies had raised about the proposed rule. These 
agencies included the Environment and Natural Resources Division of the 
Department of Justice, (DOJ/ENRD); Fish and Wildlife Service (FWS), 
Bureau of Land Management, Office of Environmental Policy and 
Compliance and National Park Service from the Department of the 
Interior (DOI),\1\ the Office of Ground Water and Drinking Water, Oil 
Program Center, and Region 3 from the Environmental Protection Agency 
(EPA); the National Transportation Safety Board (NTSB), the Council on 
Environmental Quality (CEQ); and the Office of Management and Budget. 
Where we have made changes to the rule to address comments these 
agencies raised during the discussions, we have so indicated.
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    \1\ The Department of the Interior submitted comments to the 
docket in the USA rulemaking (RSPA-99-5455). We will consider and 
address those comments in that rulemaking. The DOI comments we 
discuss in this rulemaking were made during the inter-agency 
meetings.
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1. Clarity and Specificity in the Proposed Rule
    The proposed rule used primarily performance-based language to 
allow operators to use pipeline- and location-specific information to 
determine the necessary integrity management practices. The proposed 
rule used specification language to prescribe the required elements of 
an integrity management program and baseline assessment plan, the 
allowable methods of integrity assessment and the required intervals 
for conducting baseline and continual assessments. The proposed rule 
also specified that an operator was to follow best industry practices 
unless a rule section specified otherwise or the operator could justify 
reasons for deviating from such practices and that the deviation was 
supported by a reliable engineering evaluation.
    The proposed rule recognized that an integrity management program 
was an evolving program that an operator needed to continually improve.
    API and the liquid operators supported the proposed rule's holistic 
approach to pipeline integrity management that incorporated risk 
assessment and risk-based decision making. API further praised the use 
of performance-based language in OPS's regulations. Koch commented that 
``a pipeline integrity management program allows an operator to 
consider the unique factors that impact a specific pipeline or pipeline 
segment and is more effective in improving pipeline safety than 
prescriptive regulations that treat all pipelines, no matter what their 
characteristics or where they are located, the same.''
    Environmental Defense, other advocacy groups, and other commenters 
maintained that the rule should have more specific requirements. These 
commenters stated that without such specificity, OPS would not be able 
to evaluate the adequacy of operator programs and enforce the rule. The 
City of Austin cautioned against a performance-based approach and urged 
us to clearly define the performance requirements and standards for 
monitoring, inspection and response.
    NTSB reiterated its ongoing concern that OPS have regulations that 
contain measurable standards for performance.
    EPA Oil Program Center commented that the proposed rule failed to 
include the specific requirements for an integrity management program 
or the process for determining if a pipeline will affect a high 
consequence area. The City of Austin said the rule should

[[Page 75382]]

require an operator to determine the potential impact for a worst case 
spill. Colonial Pipeline recommended that the rule clarify, either in 
the regulatory language or through guidance, how pipelines outside the 
high consequence area could affect the area.
    API recommended that the rule recognize the value of planning 
changes and allow an operator to make changes to the baseline 
assessment plan.
    DOJ/ENRD expressed concern that the proposed rule's language about 
an integrity program being an evolving program that an operator had to 
continually improve left too much to the operator's discretion. DOJ/
ENRD had similar concerns with the language about an operator using and 
documenting a practice other than a standard industry practice. DOJ/
ENRD further thought a deviation from a standard practice should only 
be allowed when new technology is being used. DOJ/ENRD also strongly 
urged substantial revisions of the proposed rule to improve its 
enforceability. DOJ/ENRD wanted clearly stated and unambiguous 
requirements for specific actions that achieve measurable results, the 
violation of which subject the operator to meaningful penalties.
    NTSB expressed concern about the proposed rule's use of the term 
best industry practices without explaining where these practices could 
be found. EPA Region III also questioned who would be responsible for 
establishing, compiling, and disseminating the best industry practices.
    API commented that the term best industry practices may cause 
controversy over its meaning and suggested that the term proven 
industry practices would be more appropriate.
    Response:
    To achieve effective integrity management programs that evolve and 
take advantage of changing technologies, the final rule uses both 
performance and specification-based language.
    Based on our considerable experience with performance-based 
regulations, OPS believes that performance-based language will best 
achieve effective integrity management programs that are sufficiently 
flexible to reflect pipeline-specific conditions and risks.\2\ However, 
we recognize that certain elements of the rule need to be written in 
specification language.
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    \2\ Our using performance-based language in the rule is 
consistent with the Administration's policy of using performance-
based standards. (See Executive Order 12866, Section 1(b) The 
Principles of Regulation (September 30, 1993).)
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    Performance-based standards allow an operator to select the most 
effective processes and technologies as they become available. OPS 
wants to create incentives for operators to invest in the development 
of new technology. Because internal inspection technology and other 
integrity monitoring equipment have changed considerably in recent 
years and are expected to continue to improve, we want to encourage 
operators to use and strive to improve the best available technologies 
and processes. Thus, rather than only specify the use of currently 
available technologies, parts of the rule are performance-based to 
allow operators to develop customized programs that address pipeline-
specific characteristics, are fully integrated into company safety and 
environmental protection programs, and use the best available 
technologies to assess and repair pipelines.
    The specification parts of the rule ensure uniformity among 
integrity management programs so that they all address key issues, such 
as baseline and continual integrity assessment intervals, information 
integration and analysis requirements, and time frames to review and 
analyze integrity assessment results and to complete remedial actions.
    As suggested by commenters, we have revised the rule to allow an 
operator to modify its baseline assessment plan and to clarify the 
basis for an operator changing and improving its integrity management 
program. We have added a provision allowing an operator to modify its 
baseline assessment plan so long as the operator documents the 
modification and reasons for the modification. An operator would have 
to document any modification at the time the decision is made to modify 
the plan, not at the time the modification is implemented. OPS 
enforcement personnel would review these supporting documents during a 
field inspection.
    Although reworded, the rule still provides that an integrity 
management program is a continually changing program. However, the rule 
now specifies that an operator must continually change the program to 
reflect operating experience, conclusions drawn from results of the 
integrity assessments, and other maintenance and surveillance data, and 
evaluation of consequences of a failure on the high consequence area. 
The rule also clarifies that an operator's integrity management program 
will evolve from the initial program framework the operator develops.
    We have revised the rule to clarify that the integrity management 
program requirements apply to each pipeline segment that could affect a 
high consequence areas. An operator's program must address the risk 
factors each pipeline segment poses to a high consequence area.
    The proposed rule specified required elements of an operator's 
integrity management program. Other than some minor word changes and 
edits, we have not changed those elements in the final rule. We believe 
these elements will ensure sound integrity management programs.
    However, to address commenters' concerns that the proposed rule 
failed to specify a process for determining if a release could affect a 
high consequence area, we have added two related requirements: that, as 
a first step, an operator identify all pipeline segments that could 
affect a high consequence area and also include a process in its 
program for identifying which pipeline segments could affect a high 
consequence area. (Identifying those segments that could affect an area 
involves determining if a release from a segment in or near a high 
consequence area could affect the area.) Although we did not propose 
these requirements in the notice, we believe they were implicit. 
Whether explicitly stated or not, an operator would have to identify 
which pipeline segments could affect a high consequence area before 
determining how the line pipe in those segments would be assessed. 
Moreover, since the trigger for the integrity management program 
requirements is whether a pipeline segment could affect a high 
consequence area, an essential element must be a process for 
identifying those pipeline segments that could affect the defined high 
consequence areas. In the Appendix to the rule, we have also provided 
guidance to help an operator in identifying high consequence areas and 
in evaluating how a pipeline release could affect a high consequence 
area. This guidance will help an operator in developing the required 
process.
    The final rule requires that an operator follow recognized industry 
practices unless the rule otherwise requires a different practice or 
the operator can demonstrate that an alternative practice is supported 
by a reliable engineering evaluation. Paragraph (b)(3) does not affect 
an operator's obligation to comply with all other requirements in this 
rule. In the final rule, we have changed the term best industry 
practices to recognized industry practices. We believe this is an 
easily understood term by operators and enforcement personnel. 
Recognized industry practices include those found in national consensus 
standards or reference guides, and generally conform to the practices 
of the American

[[Page 75383]]

National Standards Institute. Companies' successful use of these 
practices helps determine their validity and acceptance. We have 
further revised the provision to clarify the basis for an operator 
using an alternative practice. The rule now provides that an operator's 
selection of an alternative must be based on a reliable engineering 
evaluation. Use of an alternative must provide an equivalent level of 
public safety and environmental protection. An operator must document 
its use of an alternative practice from when the operator makes the 
decision to use the alternative. An operator must be able to provide 
the documentation to OPS enforcement personnel for review during a 
field inspection.
    We have not limited an operator's use of alternative practices to 
only when new technology is being used. For example, an alternative 
practice could be one that has been successfully used in other 
countries or by other pipeline companies but has not yet been codified 
into a national consensus standard. OPS wants to encourage operators to 
use innovative practices that are based on sound engineering judgment. 
OPS also wants to encourage innovation in technology and recognizes 
that an existing technology may be improved and given a new 
application.
    We have also revised language throughout the rule to make the rule 
clearer and more understandable. These changes have not affected the 
requirements of the rule, most have simply been made to improve the 
rule's overall clarity and to ensure the consistency in use of terms. 
Others have been made to address DOJ's concerns about making the rule 
more specific and enforceable and clarifying the operator's required 
responsibilities under the rule. Any substantive changes are discussed 
in this document.
2. Remedial Actions--Proposed Section 195.452(g)
    The proposed rule required an operator to take prompt action to 
address all pipeline integrity issues raised by the integrity 
assessment and data integration analysis. The rule proposed that an 
operator evaluate and repair all defects that could reduce a pipeline's 
integrity, and establish an evaluation and repair schedule. The rule 
did not propose time frames for making the repairs, other than an 
operator could not operate the affected part of its pipeline system 
until it had corrected a condition presenting an immediate hazard. The 
NPRM also asked for comment on whether the rule should contain specific 
time lines for conducting repairs.
    API was against specific time lines and said that criteria for when 
repairs should be implemented could not be reduced to simple statements 
suitable for inclusion in the rule. API added that the consensus 
standard will offer guidance to operators. Enbridge stated that a one-
size-fits-all time frame for conducting repairs is not practical or 
technically justified; however, Enbridge said that it supported the 
goal of ensuring that no imminent hazard is left unaddressed.
    Environmental Defense recommended a relatively short time to 
conduct repairs after serious defects are identified, e.g., one month 
to complete repairs unless pipeline pressure is significantly reduced. 
The City of Austin said that the rule should include repair time lines, 
acceptable methods of remediation and a better definition of what 
pipeline flaws constitute an immediate hazard. The City of Bellingham 
also recommended that the rule establish a specific and expeditious 
deadline for conducting repairs. EPA Region III commented that the 
proposed rule did not define what conditions constituted immediate 
hazard conditions.
    Peoples Energy commented that the proposed language about which 
anomalies an operator had to evaluate and repair only applied to 
defects that could reduce integrity. Peoples Energy pointed out that 
this determination could not be made until an operator reviewed all 
data.
    DOJ/ENRD questioned the ability to enforce performance-based 
standards, particularly with respect to the proposed repair provisions. 
DOJ/ENRD requested that the regulation be written in language that 
requires an operator to take specific action. DOJ/ENRD based its 
concerns on its experience with enforcing the Clean Water Act. DOJ/ENRD 
was particularly concerned that the proposed rule would not ensure that 
repairs were made before failures occurred and strongly recommended 
that language be added specifying when an operator would have to make 
repairs on the pipeline. DOJ/ENRD also strongly urged that the rule 
include a provision establishing a cut-off time for when an operator 
had to review and analyze the results from an internal inspection, and 
recommended a phased-in approach.
    Response: We have rewritten the remedial action section of the 
final rule to accommodate DOJ/ENRD's and other commenters' concerns. To 
be consistent with the wording used to describe required program 
elements, we have renamed the section to reflect the broader actions an 
operator must take to address integrity issues raised by the 
assessments. The rule has been revised to specify time frames for 
reviewing and analyzing the results of an integrity assessment and for 
completing repairs of certain conditions (see Sec. 195.452(h)).
    The rule still requires an operator to take prompt action to 
address all pipeline integrity issues raised by the integrity 
assessment and information integration. The rule now clarifies that an 
operator is required to evaluate all anomalies and repair those that 
could affect the pipeline's integrity. Prompt action means that an 
operator must make the repair as soon as practical. However, an 
operator must prioritize the repairs according to the severity of each 
anomaly and address first those anomalies that pose the greatest risk 
to the pipeline's integrity.
    The rule now requires that an operator complete repairs according 
to a schedule that prioritizes anomalies found during the integrity 
assessment for evaluation and repair. In this schedule, an operator 
would have to provide for review and analysis of the integrity 
assessment results by a date certain. The review and analysis must be 
done by a qualified person (i.e., a person who has the requisite 
knowledge and technical expertise to review the results and analyze the 
data.) For the first three years after the rule's effective date, an 
operator would determine the period by which the results would have to 
be reviewed and analyzed and commit that date in writing in its 
schedule. After the third year, an operator's schedule must provide for 
review and analysis of the integrity assessment results within 120 days 
of conducting each assessment. The rule allows more flexibility in the 
first three years so that OPS can review the adequacy of time frames 
operators establish, and gather sufficient information to determine 
what the required standard for review and analysis of assessment 
results should be. OPS recognizes that a time frame depends, in part, 
on the availability of persons with expertise to evaluate the data. OPS 
further recognizes that a quality review and analysis takes time. By 
the end of the third year OPS will have sufficient information to be 
able to determine if it should revise the 120-day required period.
    An operator's schedule also has to provide time frames for 
evaluating and completing repairs. A qualified person must conduct the 
evaluation (i.e., a person with the requisite knowledge and technical 
expertise.) Because an operator must prioritize the repairs, the rule 
provides that the operator is to base the repair schedule on specified 
risk factors and pipeline-specific risk factors

[[Page 75384]]

the operator develops. For conditions not specified in the rule, the 
operator determines the schedule for evaluation and repair. However, 
the rule provides the time frames in which an operator must complete 
repair of certain conditions on the pipeline. These conditions are 
listed as immediate repair conditions, 60-day conditions and 6-month 
conditions. The time frame required for repair starts at the time the 
operator discovers the condition on the pipeline, which occurs when an 
operator has adequate information about the condition to determine the 
need for repair. Depending on circumstances, an operator could have 
adequate information when the operator receives the preliminary 
internal inspection report, gathers and integrates information from 
other inspections or the periodic evaluation, excavates the anomaly, or 
receives the final internal inspection report.
    In the proposed rule we used the term immediate hazard for certain 
conditions, and referenced Sec. 195.401(b). In the final rule we refer 
to these as immediate repair conditions and identify several. Under 
Sec. 195.401(b), an immediate hazard condition requires that an 
operator shut down the pipeline until the operator has corrected the 
condition. With an immediate repair condition, as long as safety is 
maintained, an operator will either be able to temporarily reduce 
operating pressure or shut down the pipeline until the operator can 
complete the repair of the condition.
    An operator may deviate from the rule's specified repair times if 
the operator justifies the reasons why the schedule cannot be met and 
that the changed schedule will not jeopardize public safety or 
environmental protection. OPS enforcement personnel will review any 
justifications and supporting documents during site inspections. In 
certain cases when an operator cannot meet the required schedule and 
cannot provide safety through a temporary reduction in operating 
pressure, the operator must notify OPS. This will allow OPS to 
determine the extent of review needed and if an inspection is needed. 
The rule specifies how an operator must notify OPS.
    In the NPRM we discussed the consensus standard that an ANSI 
workgroup was developing on integrity management. OPS has been 
participating in the work group. In the notice, we said that we would 
consider adopting all, or part of, the standard once it was final, but 
only after public notice and comment. (More discussion about the 
consensus standard appears later in this document under the topic 
heading ``Consensus standard on pipeline integrity.'') The standard is 
not yet final. However, OPS is basing the provisions in section 
195.452(h) on initial indications of what will be in the final 
consensus standard. We believe that the criteria being considered by 
the standard's workgroup adequately address pipeline integrity concerns 
because the criteria are based on a structured methodology for 
evaluation of internal inspection devices data. The methodology is a 
recognized industry practice. The criteria are also based on well-
established consensus standards, such as the American Society of 
Mechanical Engineers (ASME) B31.4 standard. ASME B31.4 is a widely-
recognized and long accepted standard on liquid transportation systems 
for hydrocarbons, liquid petroleum gas, anhydrous ammonia, and 
alcohols. (The regulations in 49 CFR Part 195 were developed from ASME 
B31.4.)
    Although a consensus integrity standard is not yet final, we have 
made available at OPS's website, notes of the meetings, and a peer 
review draft of the standard on Managing Pipeline System Integrity. The 
standard is expected to be completed and published in December, 2000.
    We recognize that we have completely restructured the section of 
the rule pertaining to actions an operator must take to address 
pipeline integrity issues. Because of the extensive changes to this 
section of the rule, we are allowing 60 days comment on the provisions 
in section 195.452(h). Based on the comments we receive, we will 
consider modifying the provisions. At the end of the comment period, we 
will either issue a modification or a notice stating that the section 
stands as written.
    An operator has one year from the effective date of the rule to 
develop the framework for an integrity management program. An operator 
has 3\1/2\ years from the rule's effective date to conduct a baseline 
integrity assessment of the highest risk line pipe segments. An 
operator is not likely to take remedial actions required by this rule 
until after the integrity assessment. Thus, remedial action criteria 
are not needed until some time after the rule's effective date. We 
expect to issue any modifications so that operators have ample time to 
incorporate the modifications into their program framework. If we are 
delayed in issuing the modification so that operators do not have 
adequate lead time, we will then consider further delaying the 
compliance date for section 195.452(h). Until OPS announces a 
modification, operators can base their program remedial action criteria 
on those set forth in this rule.
3. Review, Approval and Enforcement Processes
    Some commenters questioned why the proposed rule did not provide 
for adequate and timely OPS review and approval of an operator's 
baseline plan, integrity assessments, and integrity program. The 
proposed rule requires an operator to maintain for inspection written 
documentation of its program and assessment plan, and of any evaluation 
or analysis made to support a decision or action. The rule did not 
propose requirements for formal transmittal of baseline assessment 
plans, assessment results, or integrity management programs to OPS for 
approval.
    Lower Colorado River Authority (LCRA) supported the flexibility of 
a performance-based approach but cautioned that the commensurate 
accountability component seemed to be missing. LCRA explained that the 
proposed rule did not provide a mechanism for OPS review, or approval 
of critical decisions made by an operator or indicate that OPS would 
have any involvement in program implementation. The City of Austin 
maintained that the proposed rule seemed to continue reliance on the 
regulated community to implement pipeline safety regulations at their 
own discretion, with only minimal regulatory oversight. The City of 
Austin cautioned that close regulatory review and oversight are needed 
and strongly urged OPS to require all integrity management programs to 
be submitted for OPS approval, as well as assessment reports.
    EPA Oil Program Center expressed concern that the proposed rule 
relied ``heavily on a pipeline operator's assessments, assumptions, and 
evaluations, yet requires no formal approval process by the Office of 
Pipeline Safety or certification by a third party, such as a 
Professional Engineer.''
    Several commenters questioned OPS's ability to adequately enforce 
the proposed rule because of inadequate data, knowledge, or expertise. 
EPA Region III stated that the bulk of expertise in this subject area 
seemed to reside with the pipeline industry because of the proposed 
rule's reliance on industry's efforts to evaluate and resolve risk 
issues concerning pipelines. Region III further stated that OPS must 
obtain and/or develop independent expertise and knowledge for effective 
oversight. Friends of the Aquifer commented that because of the lack of

[[Page 75385]]

accurate data about pipeline spills, OPS would not be able to judge the 
adequacy of the risk factors included in an operator's plan.
    Response: OPS agrees that an effective and credible inspection 
process is critical to achieving the objectives of the rule. OPS is 
developing protocols and criteria for detailed inspection of operator 
baseline assessment plans and integrity management programs to ensure 
that operators comply with the requirements of the rule, and that 
operators use structured, documented, and technically defensible 
processes and models to support assessment priorities and time frames, 
decisions on remediation, prevention and mitigation, and measures of 
program effectiveness.
    OPS has already developed expertise in enforcing performance-based 
regulations and in evaluating risk-based decision processes. OPS has 
contracted for additional training in specific technical areas to 
improve the qualifications of its enforcement personnel. OPS plans to 
have a sufficient base of trained enforcement personnel who will review 
the integrity management programs during on-site inspections of 
pipeline operators. OPS will contract for any needed technical 
expertise to supplement the knowledge of its enforcement personnel.
    We are not requiring formal approval of an operator's integrity 
management program or of decisions and analyses made to develop and 
implement the program. Rather, a multi-disciplined team composed of OPS 
regional inspectors, and technical specialists from headquarters will 
conduct integrity management program inspections. In addition, OPS will 
contract for other technical expertise, as needed. We are also planning 
how best to involve state pipeline safety inspectors in the review.
    We have also added requirements that an operator provide advance 
notice to OPS when the operator plans to use other technology (other 
than internal inspection or pressure test) for a baseline or continual 
integrity assessment or intends to justify a longer continual 
assessment period. (We discuss these advance notice requirements later 
in the document.) We determined that an advance notice requirement was 
necessary in certain instances to give OPS enforcement personnel 
additional time to review and evaluate an operator's rationale and 
supporting documentation.
    The rule continues to require an operator to document all aspects 
of its integrity management program so that OPS enforcement personnel 
can review these documents during an inspection to determine an 
operator's compliance with the rule. We have clarified the language in 
the final rule concerning the types of documents an operator is 
required to maintain. Required documents include those to support 
decisions and analyses made, as well as modifications, justifications, 
deviations, variances and determinations made, and actions taken to 
implement and evaluate each of the required program elements. This 
requirement is no different from other requirements in the pipeline 
safety regulations that an operator maintain current maps and records 
of its pipeline system, maintain a procedural manual for operations, 
maintenance and emergencies and maintain other records of tests and 
inspections. In Appendix C we have provided some examples of records an 
operator would have to maintain for inspection. We also discuss 
recordkeeping requirements in greater detail later in this document in 
the section by section analysis (section 195.452(1)).
4. Program Implementation and Integrity Assessment Time Frames, 
Assessment Methods and Criteria--Proposed Sections 195.452(b)-(e) and 
(j)
    The notice proposed that an operator develop and follow a written 
integrity management program within one year after the final rule's 
effective date. The proposed rule included a seven-year time frame for 
the baseline assessment, with an operator having to assess 50% of the 
mileage within 3.5 years, and a ten-year maximum interval for continual 
integrity re-assessments. The notice proposed that an operator conduct 
the integrity assessment by internal inspection, pressure test, or new 
technology that could provide equivalent protection to the other two 
methods.
    The proposed rule disallowed use of a magnetic flux leakage or 
ultrasonic internal inspection device for a pipeline segment 
constructed of low frequency ERW pipe or lapwelded pipe susceptible to 
longitudinal seam failures. This was done to be consistent with current 
requirements in section 195.303 providing that an operator's program 
for testing a pipeline on risk-based criteria provide for pressure 
testing of a segment constructed of either of those types of pipe.
    The notice also proposed allowing as a baseline assessment an 
integrity assessment that an operator had conducted within five years 
prior to the effective date of a final rule.
    The proposed rule permitted an operator to choose between two 
options in establishing baseline and continual assessment schedules. 
The first option specified risk factors to use in establishing the 
schedule. The second option permitted an operator to base the schedule 
on risk factors the operator considered essential in risk or 
consequence evaluation. This option would have given an operator some 
flexibility to establish re-assessment intervals exceeding ten years.

Implementation

    API recommended that program implementation be keyed to OPS making 
available to operators a complete set of maps designating the high 
consequence areas rather than to the final rule's effective date.
    The National Pipeline Reform Coalition objected to the one-year 
program development period based on OPS's estimate in its cost/benefit 
analysis of how long it would take an operator to develop an integrity 
management program. OPS had estimated 430 hours.

Assessment Time Frames

    API and the industry commenters suggested that OPS establish 
January 1, 1995 as the cut off date for acceptability of prior 
integrity assessments, rather than tying the cutoff date to a final 
rule date. Enbridge and Lakehead asked that operators be allowed to 
justify older assessments, rather than OPS arbitrarily excluding those 
older than five years.
    API also said that the proposed seven-year baseline and ten-year 
re-assessment periods were reasonable, and would allow operators to 
make decisions based on the characteristics of their pipeline 
system.The hazardous liquid operators re-iterated and concurred with 
API's comments.
    Advocacy and environmental groups, and other commenters objected to 
the proposed seven-year baseline assessment and ten-year re-assessment 
periods. Some also objected to allowing a five-year old prior 
assessment to satisfy the baseline assessment. Environmental Defense 
suggested a three-year maximum, only allowing baseline assessments that 
have occurred within two years of the rule. For the continual re-
assessment interval, Environmental Defense recommended that OPS follow 
the California model, and require re-assessment every five years. The 
City of Bellingham suggested that baseline assessments should be 
completed in one to three years, and periodic updates within five 
years. Fuel Safe Washington objected to allowing any prior baseline 
assessments, and suggested that baseline assessment be completed within 
18 months, and that re-assessment be required at a maximum of five 
years, three years for pipelines constructed prior to 1970, and one 
year

[[Page 75386]]

for pipelines located in unusually sensitive environmental areas. 
Pipeline Survivor's Association argued that baseline assessments should 
be completed in three years, with 50% of that mileage being assessed in 
18 months, prior assessments be limited to one year before the rule, 
and re-assessments intervals be shortened to five years. The City of 
Austin recommended five years for establishing the baseline, 2.5 years 
to complete 50% of the baseline, and five years for reassessment. 
Batten & Associates recommended a baseline assessment period of three 
years, limiting prior allowable integrity assessments to one year 
before the rule's effective date, and re-assessment intervals of three 
years. LCRA recommended a seven-year time frame for completing the 
baseline integrity assessment and shortening the ten-year time frame 
for re-assessment in some instances based on pipeline-specific risk 
factors (e.g., age of pipe, leak history, etc.).
    Several federal agencies also objected to the proposed integrity 
assessment time frames. NTSB urged us to reduce the period for the 
baseline assessment because it could not find sufficient data in the 
proposed rule to justify the seven-year period. EPA Oil Program Center 
suggested a five-year time frame for completing the baseline, with 50% 
of the mileage completed within 30 months. EPA Region III also 
recommended a five-year continual assessment period because it would 
provide useful integrity/deterioration information, without imposing 
too great a burden. DOJ/ENRD raised concern with the proposed seven-
year baseline and ten-year continual assessment intervals and strongly 
recommended shorter baseline and continual integrity assessment 
intervals. DOJ/ENRD said OPS could not demonstrate that defects would 
not propagate to failure within the proposed seven-year period. DOJ/
ENRD also questioned the basis for OPS's assumption that a ten-year 
interval was reasonable if a pipeline was adequately cathodically 
protected.

Assessment Schedule Criteria

    The City of Austin recommended eliminating Option 2--allowing an 
operator to establish an assessment schedule based on factors it 
determines essential--because it would not be feasible for an operator 
to demonstrate ``an equivalent level of safety and environmental 
protection as Option 1 given the extremely complex inter-workings of 
the many potential risk factors.'' The advocacy groups argued for 
dropping Option 2 from the rule because it provided the operator too 
much discretion. EPA Region III also stated that Option 2 may provide 
``too loose a regimen'' and supported the approach described in Option 
1. Environmental Defense preferred ``a modified Option 1 in which 
operators could identify and report any additional risk factors to 
those specified in the rule.'' The National Pipeline Reform Coalition 
also recommended eliminating Option 2 because Option 1 allowed enough 
flexibility for an operator to determine that a specified risk factor 
had little or no applicability to its operations and discount the 
factor.
    Several commenters suggested risk factors that the rule require for 
establishing assessment frequency. NTSB recommended that OPS not let an 
operator determine what factors are essential for ensuring a pipeline 
system's safety and environmental protection; rather the rule should 
specify minimum factors that an operator must consider in establishing 
an assessment schedule. NTSB suggested these factors include the 
results from previous inspections, the pipeline's leak history, 
material and coating conditions, cathodic protection history, type of 
pipe seams, product transported, operating pipe stress levels, defect 
types and sizes detectable by the inspection method used, defect growth 
rates, and effectiveness of actions taken to correct chronic problems, 
such as corrosion. EPA Region III suggested that risk factors for 
establishing frequency of assessment should also include, product 
specific differences, location related to the ability of the operator 
to detect and respond to a leak (e.g., pipelines deep underground) and 
non-standard or other than recognized pipeline installations (e.g., 
horizontal directional drilling).
    National Pipeline Reform Coalition suggested risk factors such as 
pipe material and manufacturing processes, highly corrosive soils, and 
highly volatile products being transported. Dynegy suggested that 
highly volatile liquids not be treated as other hazardous liquids 
because they do not pose the same potential for damage to sensitive 
environmental areas. SEFBO recommended that the rule distinguish 
overhead suspension pipeline bridges from other above ground pipeline 
support structures because more sophisticated skills and experience are 
required to inspect and maintain cable structures. Sen. Breaux also 
urged that we address the role of these bridges in high consequence 
areas.

Assessment Methods

    API expressed satisfaction that the proposed rule not only 
recognized that internal inspection tools provide valuable information 
but also recognized that a single tool or integrity assessment 
methodology is not always the answer, and that integrity can be 
assessed by various inspection methods. API and Equilon, however, 
suggested that we delete the footnote in the proposed rule preventing 
operators from using magnetic flux or ultrasonic internal inspection 
tools on low frequency electric resistance (ERW) welded pipe. API 
suggested language to ensure that the integrity of ERW seams is 
adequately assessed. Colonial Pipeline was pleased that the rule 
recognized the value of internal inspection technology and recognized 
that technology is constantly evolving.
    Koch suggested that the rule allow an alternative assessment 
methodology in situations where it would be appropriate to conduct an 
assessment by means other than internal inspection, pressure test, or 
equivalent new technology. Peoples Energy questioned why the proposed 
rule did not allow for use of current technology, such as sonic or 
optical methods, that could be made feasible for pipelines.
    Dynegy pointed out that a leak during a hydrostatic test could 
damage the environment and that installing magnets needed for 
instrumented internal inspection could also damage an area.
    Response:

Implementation

    The final rule keeps the one-year period from the rule's effective 
date for an operator to develop an integrity management program. 
However, the rule now requires that an operator identify all pipeline 
segments that could affect high consequence areas within nine months 
from the rule's effective date. Although implicit that an operator 
would have to identify the pipeline segments that were covered by the 
rule, the proposed rule did not propose that an operator do this. 
Because identification is a necessary first step in the integrity 
management process, we did not think it unreasonable to make it an 
explicit requirement.
    We have also clarified that during the first year an operator must 
develop a program framework that addresses each element of the 
integrity management program. The rule further clarifies that a program 
begins with the initial framework. Once the program framework is 
developed, an operator will then have to implement and follow the 
program. Because an integrity management program is dynamic, the rule 
provides that an operator must also continually change the program as 
the operator gains experience.

[[Page 75387]]

Assessment Intervals

    We have not revised the time period for an operator to conduct a 
baseline assessment. OPS believes that a seven-year baseline integrity 
assessment cycle will result in a higher quality integrity assessment 
and analysis of the assessment results to better ensure the integrity 
of each pipeline segment. Further, OPS believes that this schedule will 
effectively double the rate of assessment currently being conducted. 
Finally, we decided not to establish a shorter baseline interval 
because an analysis OPS conducted found that internal inspection 
resources needed to meet demand for baseline assessment are marginally 
adequate until the year 2007. This finding took into account resources 
that will be needed concurrently for other assessments (apart from 
those this rule requires). (See memorandum from Noel Duckworth, dated 
October 1, 2000. This memorandum is in the docket.) We expect that 
internal inspection will be the primary choice of operators. Moreover, 
once we establish similar integrity management program requirements for 
liquid operators with smaller operations and for natural gas operators, 
these operators will all be drawing on the same market of vendors. 
Thus, to ensure that operators have adequate time to conduct high 
quality integrity assessments and to analyze the results from the 
assessments, we have kept the seven-year baseline interval.
    Moreover, to ensure that the highest risk pipe is assessed early in 
the cycle, we have clarified that an operator must assess at least 50% 
of the pipe, beginning with the highest risk pipe, in the first 3.5 
years of the seven-year baseline period. This requirement, coupled with 
the requirement to base the assessment intervals on risk-based factors 
and analyses, should ensure that an operator assesses the highest risk 
segments in a shorter time frame. An operator's schedule and rationale 
for establishing the assessment intervals are subject to review during 
an inspection.
    The rule continues to allow as a baseline assessment an integrity 
assessment that an operator has conducted five years before the rule's 
effective date. However, we have revised the rule so that if an 
operator chooses to use a prior integrity assessment, the operator must 
then re-assess the pipe segment according to the continual integrity 
re-assessment requirements (discussed below). We believe that some 
operators will opt for using a prior integrity assessment to address 
integrity issues on a pipeline segment that need prioritized remedial 
action.
    One of the greatest concerns expressed by Federal government 
agencies, environmental groups and other advocacy groups (as discussed 
above) was that the proposed ten-year continual re-assessment interval 
was too long to ensure public safety and environmental protection. 
Because of the concern expressed, we did additional research and 
reconsidered the issue. Based on what we found, we have revised the 
final rule to shorten the continual re-assessment interval. The rule 
now requires an operator to establish intervals not to exceed five (5) 
years for continually assessing the line pipe's integrity, unless the 
operator can demonstrate that one of the limited exceptions applies.
    In deciding on the five-year interval, we relied extensively on an 
analysis OPS conducted on internal inspection devices (Noel Duckworth 
memorandum dated October 1, 2000). The analysis is available in the 
docket. The analysis found that, in 1999, the three major internal 
inspection devices vendors in the U.S. logged 30,000 miles, at 68% 
utilization capacity, and in 2000, the vendors expect to log 45,000 
miles at 90% utilization (maximum attainable). According to the 
memorandum, the analyst estimated that the total capacity of these 
three internal inspection device vendors would likely increase to about 
87,000 miles by 2007. Our current estimates indicate that this rule is 
likely to apply to 35,500 miles of hazardous liquid pipeline. (Because 
of the location of pig launchers and receptors, which are typically 
located near pump stations 50 miles apart, operators will be internally 
inspecting more than the 35,500 miles of hazardous liquid pipeline 
required under the rule. We expect that at least 25-30% additional 
mileage or 44,375 miles will be internally inspected.) Additional 
internal inspection requirements will also be generated by future rules 
that will apply to smaller hazardous liquid operators and to natural 
gas operators. Therefore, according to the Duckworth memorandum, the 
three big vendors should be able to meet the demand for internal 
inspection devices, although demand will stress the capacity of the 
market. The memorandum noted that more is involved in integrity 
assessment than just running the internal inspection devices, and 
analyzing the data, but also about the planning/scheduling process 
between internal inspection tool companies and pipeline operators. 
Based on these findings, coupled with the insistent urging of several 
federal agencies (DOJ, NTSB, and EPA), and many other commenters, who 
argued that a shorter continual integrity re-assessment interval was 
essential to protect public safety and the environment, we have reduced 
the re-assessment interval to a general requirement of five years, 
providing for exceptions.
    The five-year integrity re-assessment period is not absolute. The 
rule allows variance in limited instances from the five-year period: 
when there is an engineering basis for a longer period or when the best 
technology needed to assess the segment is temporarily unavailable. For 
example, an operator may be able to justify an engineering basis for a 
longer assessment interval on a segment of line pipe, if the operator 
can support the justification by a reliable engineering evaluation 
combined with the use of other technology, such as external monitoring 
technologies, that provides an equivalent understanding of the 
condition of the line pipe. Or an operator may require a longer 
assessment period for a segment of line pipe because the best 
assessment technology, given the risk factors of the segment, is not 
available. An operator would then have to justify the reasons why it 
could not comply with the required assessment period and also 
demonstrate the actions it is taking to evaluate the integrity of the 
pipeline segment in the interim. In either instance, an operator would 
have to notify OPS before the end of the five-year period that the 
operator will be justifying a longer period. If the justification is 
based on engineering reasons, the operator must provide nine months 
notice before the end of the five-years. For unavailable technology, 
the operator must provide 90-days notice. Advance notice will give OPS 
sufficient lead time to review an operator's justification and 
supporting documents.
    The rule continues to require that an operator base both the 
baseline and continual assessment intervals on the risk the pipeline 
segment poses to the high consequence area. To establish the assessment 
intervals, the rule requires that an operator use specified risk 
factors, the analysis of the results from the last integrity 
assessment, and information from the integration analyses. These 
factors and information will help the operator to prioritize the 
pipeline segments for assessment.
    OPS inspectors will carefully evaluate each operator's methodology 
for determining the baseline and continual integrity assessment 
schedules to ensure that the highest risk segments are being addressed 
in the earliest time frames. OPS inspectors will also review an

[[Page 75388]]

operator's justification for deviating from the required five-year re-
assessment interval. We have added the requirement for advance notice 
to OPS when an operator may vary from the five-year interval so that 
OPS inspectors have adequate time to review and evaluate the 
justification supporting the variance.

Assessment Criteria

    We agree that appropriate flexibility for establishing an 
assessment schedule based on risk factors can be achieved by modifying 
Option 1 and deleting Option 2. The final rule requires that an 
operator base its integrity assessment schedule on all risk factors 
that reflect the risk conditions on the pipeline segment. The rule also 
specifies certain factors that an operator must consider. These factors 
include those we proposed in the NPRM plus others suggested by NTSB, 
EPA, the THLPSSC and other commenters. However, the rule does not 
preclude an operator from including other risk factors specific to the 
pipeline being assessed. OPS wants to encourage operators to supplement 
the specified risk factors with factors relevant to the pipeline 
segment being assessed.
    We have not changed the final rule to establish separate 
requirements for highly volatile liquids and other hazardous liquids, 
or for overhead suspension pipeline bridges. However, because highly 
volatile liquids and overhead suspension bridge pipelines may pose 
unique risks to a high consequence area, an operator's integrity 
management program must consider and address these risks. In the rule, 
we have added pipeline suspension bridges and product transported to 
the list of factors an operator must consider when establishing an 
assessment schedule. The Appendix provides an operator further guidance 
on establishing integrity assessment intervals.

Assessment Methods

    The rule continues to allow a choice in the integrity assessment 
method--internal inspection tool, pressure test, or other technology 
that an operator demonstrates can provide an equivalent understanding 
of the condition of the line pipe. We did not provide for another 
assessment method in lieu of the three permitted methods. We believe 
that the three permitted methods give an operator sufficient 
flexibility to conduct integrity assessments appropriate to each 
pipeline segment that must be assessed.
    The rule provides that an operator choosing assessment by internal 
inspection must use a tool or tools capable of detecting corrosion and 
deformation anomalies, including dents, gouges and grooves.
    We have revised the rule to delete the footnote about not using a 
magnetic flux leakage or ultrasonic internal inspection tool on ERW 
pipe. We recognize that technology in the internal inspection industry 
has been changing rapidly. Now, there are readily available tools, for 
example, ultrasonic (shear wave) and circumferential magnetic flux 
leakage tools, that can detect longitudinal seam failures. Therefore, 
the rule now allows an operator to use integrity assessment methods on 
ERW pipe and on lapwelded pipe susceptible to longitudinal seam 
failures that can assess seam integrity and can detect corrosion and 
deformation anomalies. An operator's integrity management program would 
also have to address the special risks of these types of pipe.
    In the final rule we clarified that a pressure test must be 
conducted according to the requirements for pressure testing found in 
Part 195, subpart E. An operator choosing to assess by pressure test 
should also evaluate its corrosion control program before deciding on 
this option.
    OPS inspectors will review the operator's selection of assessment 
methods for the relevant pipeline segments. OPS personnel will 
particularly look at the adequacy of the operator's corrosion control 
program when evaluating an operator's choice to pressure test.
    We used the term new technology in the proposed rule as an 
operator's third option. In the final rule, we changed that term to 
other technology. Other technology would include new or existing 
technology that is adapted for pipeline use and provides an equivalent 
understanding of the condition of the line pipe as the other two 
methods. We have also changed the language that the other technology 
must provide an equivalent level of protection in assessing the 
integrity of the line pipe to that it must provide an equivalent 
understanding of the line pipe. We believe this language better 
reflects what an assessment tool does i.e., it does not protect the 
pipe but gives the operator an understanding of the condition of the 
line pipe.
    If an operator chooses other technology as its assessment method, 
the operator must notify OPS 90 days before using the technology so 
that OPS has adequate time to review the technology.
5. Applicability (Coverage) of the Rule--Proposed Section 195.452(a)
    The proposed rule applied to operators that operate 500 or more 
miles of hazardous liquid pipeline used in transportation. If an 
operator fell into that category it would then have to develop an 
integrity management program for all segments of pipeline that could 
affect a high consequence area.
    EPA Oil Program Center, the National Pipeline Reform Coalition, and 
other advocates suggested that this rule should apply to all hazardous 
liquid pipelines. EPA Oil Program Center expressed confusion about 
whether the rule applied only to pipelines that were 500 miles long or 
longer. The City of Austin pointed out that smaller operators might be 
more likely to have poorer maintenance and operating practices. BP 
Amoco also urged OPS to require all hazardous liquid operators to 
comply with the proposed rule, expressing concerns that pipeline 
companies might structure their operations in a manner to avoid 
applicability of the rule.
    NTSB suggested that integrity management requirements should apply 
to hazardous liquid pipelines no matter where they are located, not 
just those pipeline segments that could affect high consequence areas.
    API and the individual operators commented on the need for greater 
clarity in the portions of a pipeline facility to which the rule would 
apply. These commenters said that OPS needed to clarify whether the 
integrity management program requirements were limited to the line pipe 
or were intended to cover other facilities included in the definition 
of pipeline (e.g., pump stations, valves, breakout tanks). The pipeline 
industry commenters suggested that the rule be limited to the line pipe 
and that we address integrity issues for the other pipeline facilities 
in a separate rulemaking.
    API also suggested that the final rule clarify that it is limited 
to onshore pipeline systems, and that OPS conduct a separate rulemaking 
on integrity management for offshore pipeline systems. API, and other 
industry commenters, explained that offshore lines may not be capable 
of accommodating internal inspection devices. API also noted that 
offshore pipelines pose different risks from onshore pipelines. BP 
Amoco thought it appropriate to include only offshore pipelines that 
could affect USAs in an integrity management program because offshore 
operations pose a limited, if any, risk to public safety. The company

[[Page 75389]]

listed technical factors that should be considered in establishing 
integrity requirements for these lines. Chevron also noted that 
offshore lines present technical and configurational differences from 
onshore lines.
    SEFBO and Sen. Breaux commented that the rule should clearly 
distinguish overhead suspension pipeline bridges because of the 
different skills and experience required for inspection and maintenance 
of such structures. Dynegy recommended that the rule exempt highly 
volatile liquid product pipelines that traverse wet or flooded areas, 
instead, that we cover those lines under the gas integrity management 
program rule.
    Response: The final rule clarifies that it applies to each operator 
who owns or operates a total of 500 or more miles of pipeline used in 
hazardous liquid transportation. If an operator has 500 or more miles 
of pipeline in its system, then the operator's integrity management 
program must address the risks on each pipeline segment in its system 
that could affect a high consequence area. The length of an individual 
pipeline segment that could affect the high consequence area is 
irrelevant to whether it is covered.
    Moreover, as we explained in the NPRM, we have no intention of 
excluding hazardous liquid operators with smaller operations. Our 
public discussions had given us ample information to proceed with a 
proposed rulemaking aimed at larger liquid operators. While we 
proceeded with the first part of the rulemaking (liquid operators 
owning or operating 500 or more miles of pipeline), we continued to 
obtain further information about smaller liquid operations so that we 
could propose integrity management program requirements applicable to 
those systems. The next step in our series of rulemakings that will 
ultimately require all regulated pipeline operators to have integrity 
management programs is to propose integrity management program 
requirements for hazardous liquid operators who own or operate less 
than 500 miles of pipeline.
    In this rulemaking we have not extended the pipeline integrity 
requirements to pipelines beyond those that could affect a high 
consequence area. We continue to focus on pipeline segments that could 
affect the areas we define as high consequence areas: populated areas, 
unusually sensitive environmental areas and commercially navigable 
waterways. However, we expect that many of the measures the rule 
requires for pipeline segments that could affect high consequence areas 
will benefit other parts of the pipeline system not covered by the 
rule. For example, the final rule requires an operator to analyze and 
integrate various information about the integrity of the entire 
pipeline. This analysis is likely to benefit other segments of the 
pipeline system. The additional preventive and mitigative measures that 
an operator must take to protect the high consequence area should also 
yield benefits beyond the segment in the critical area.
    Because of the location of launchers and receivers on a pipeline, 
an assessment by internal inspection is likely to benefit an additional 
25-30% of pipeline beyond that covered by this rule. An operator may 
also choose to extend the integrity assessment beyond the pipeline 
segment that could affect the high consequence area.
    The final rule clarifies the pipeline facilities covered by the 
integrity management program requirements. The integrity management 
program requirements apply to each pipeline segment that could affect 
the high consequence area. We are using the term pipeline as it is 
defined in Sec. 195.2; the term includes, but is not limited to, line 
pipe, valves, and other appurtenances connected to line pipe, pumping 
units, metering and delivery stations, and breakout tanks. Integrity 
management addresses more than material issues in line pipe, but other 
issues such as adequacy of procedures, operator training, and other 
issues related to the pipeline facilities.
    The rule clarifies that the baseline integrity assessment, which 
involves internal inspection, pressure test, or other equivalent 
technology applies only to the line pipe. (Line pipe is defined in 
Sec. 195.2.) The continual integrity assessments, done at intervals not 
to exceed five years, also are limited to the line pipe.
    The continual evaluation and information analysis requirements, 
however, apply to the entire pipeline. To ensure that a high 
consequence area receives broad protection, an operator must evaluate 
all threats to and from the pipeline, and consider how operating 
experience in other locations on the pipeline could be relevant to a 
segment that could affect a high consequence area. Thus, the rule 
requires an operator to periodically evaluate the integrity of each 
pipeline segment that could affect a high consequence area by analyzing 
all available information about the entire pipeline. This information 
would include information critical to determining the potential for, 
and preventing, damage due to excavation, including current and planned 
damage prevention activities, and development or planned development 
along the pipeline segment; information about how a failure would 
affect location of water intake; and information gathered in 
conjunction with other inspections, tests, surveillance and patrols 
required in Part 195, including, corrosion control monitoring and 
cathodic protection surveys. This information analysis will be done in 
conjunction with the periodic evaluation and continual integrity 
assessment of each pipeline segment.
    The rule does not apply to all offshore pipelines, only to those 
offshore pipeline segments (and onshore pipeline segments) that could 
affect a high consequence area. Offshore pipelines could, particularly, 
affect unusually sensitive environmental areas (USAs) and commercially 
navigable waterways. We are including these offshore pipeline segments 
because of their potential to impair unusually sensitive ecological 
resources, to disrupt the flow of goods to communities, or to impair 
unusually sensitive drinking water resources. We discuss later in this 
document all areas that are included as high consequence areas. (See 
discussion under topic heading ``Definition of High Consequence 
Areas.'') We also explain how these areas will be shown on the National 
Pipeline Mapping System (NPMS).
    We have also added offshore pipelines to the list in Appendix C of 
risk factors that an operator should consider in establishing an 
integrity assessment schedule. Generally, risks associated with 
offshore lines are because of climatic or geological factors.
    We did not accept the recommendation to exempt highly volatile 
liquid (HVL) product pipelines from this rule. (HVLs are covered under 
Part 195 because they are and behave like hazardous liquids when 
transported by pipeline under pressure.) Rather, as discussed 
previously in this document, we have added highly volatile liquids (or 
product transported) and pipeline suspension bridges to the list of 
risk factors an operator must consider in establishing an integrity 
assessment interval. And as we discuss later in the document, these 
factors have also been added to the specified factors an operator must 
consider when analyzing the need for additional protective measures for 
the pipeline segment.
6. Consensus Standard on Pipeline Integrity
    In the NPRM, OPS mentioned that API was sponsoring an American 
National Standards Institute (ANSI) work group to develop a consensus

[[Page 75390]]

standard on integrity management. We said that we expected the 
consensus standard would provide detailed guidance to operators 
developing and implementing an integrity management program. We further 
said that once the standard was final, we would consider adopting it 
into the integrity management rule, but only after we had provided a 
public notice and comment period prior to incorporating it into the 
rule. The work group is continuing its work on the standard and is 
seeking comment on the draft of the standard.
    There was a difference of opinion among commenters concerning an 
industry group's role in coordinating the development of a standard. 
Environmental Defense and other public advocates, expressed concern 
over API's role, and suggested use of a neutral engineering society. 
The City of Austin urged RSPA to develop standards using a team of 
stakeholders that includes the regulated community, local officials, 
experienced safety engineers, and other appropriate experts.
    API responded that the standard is being developed using the 
procedures of the American National Standards Institute and includes 
broad participation from operators, vendors, representatives from the 
American Society of Mechanical Engineers (ASME), the National 
Association of Corrosion Engineers, OPS, and pipeline safety advocates.
    EPA Region III said that the pursuit of an industry consensus 
standard by both the API and OPS is encouraging, but asked about the 
direct involvement in that process by OPS and other federal agencies, 
and the current review procedures for such standards.
    Response: The standard being developed will be a consensus standard 
of the American National Standards Institute (ANSI), developed using 
the standard development procedures of this independent organization. 
The work group of technical experts includes representatives from 
government, industry, and members of the American Society of Mechanical 
Engineers (ASME). When the work group was created in February 2000, 
environmental and other advocacy groups were invited to join the work 
group.
    The work group's meetings are open to the public. Public 
participation has been encouraged. Minutes of the meetings have been 
posted on OPS's website. The resulting draft standard is being 
distributed for public comment before publishing, allowing input and 
review from all stakeholders.
    The Executive Committee of ASME B31.4 has also agreed, at OPS's 
request, to undertake a peer review of this ANSI standard to ensure 
that the standard adequately addresses the regulatory requirements. The 
ASME Executive Committee is expected to complete this peer review 
during fall 2000.
    Accordingly, we believe that the on-going standard development 
process has the appropriate and adequate checks and balances built in 
to produce a technically sound product that can support the development 
and implementation of high quality integrity management programs. We 
expect this standard will provide more detailed guidance to operators 
on the specific elements and acceptable processes of an integrity 
management program, and can supplement the performance-based portions 
of the rule. Once the consensus standard is final, we will consider 
adopting, all or part of it into this final rule. However, we will only 
do so after we have provided for public notice and comment.
7. Definition of High Consequence Areas--Proposed Section 195.450
    The proposed rule's definition of high consequence areas had three 
components: populated areas, areas unusually sensitive to environmental 
damage and commercially navigable waterways.

Populated Areas

    The notice proposed that populated areas consist of high population 
areas and other populated areas. The proposed rule based these areas on 
Census Bureau definitions.
    The City of Austin thought that the population component of the 
definition was too vague. They commented that because Census figures 
were only updated every ten years, that high growth areas could be 
penalized, and that smaller clusters of dense population would not be 
included. The City wanted OPS to supplement the Census data with local 
data on utility connections. The City of Austin also stated that OPS 
incorrectly stated the Census Bureau's definition of an urbanized area.

USAs

    The environmental component of the proposed high consequence area 
definition used OPS's recently proposed definition of Unusually 
Sensitive Areas (USAs) (64 FR 73464; Dec. 30, 1999).
    Many commented that this proposed definition is too restrictive, 
and should be expanded to include all environmentally sensitive areas. 
EPA Oil Program Center expressed concern that OPS's methodology would 
fail ``to protect even the most vulnerable of sensitive environmental 
populations and their habitat.'' EPA Region III said that the 
definition should include product-specific differences. Friends of the 
Aquifer stated that ``the rule proposes an eccentric and far too narrow 
definition of natural areas .'' AWWA also commented that the USA 
definition was inadequate because it excludes many sources of drinking 
water. Environmental Defense suggested we include all environmentally 
sensitive areas without the filtering system the proposed USA 
definition used. Friends of the Aquifer also wanted all environmentally 
sensitive areas included. Batten & Associates thought the proposed USA 
definition was too restrictive and would fail to protect many drinking 
water resources and habitats for threatened and endangered species.

Commercially Navigable Waterways

    API and liquid operators questioned the inclusion of commercially 
navigable waterways into the high consequence area definition. API 
pointed out that Congress required OPs to identify hazardous liquid 
pipelines that cross waters where a substantial likelihood of 
commercial navigation exists and once identified, issue standards, if 
necessary, requiring periodic inspection of the pipelines in these 
areas. API said that OPS had not determined the necessity for including 
these waterways in areas that trigger additional integrity protections. 
BP Amoco said the rule should be limited to protection of public 
safety, rather than commercial interests. Enbridge and Lakehead also 
questioned why waterways that are not otherwise environmentally 
sensitive should be included for protection.
    EPA Region III said that we should also consider recreational and 
waterways other than those for commercial use. Environmental Defense, 
Batten, City of Austin and other commented that we should consider all 
navigable waterways as high consequence areas, because of the 
environmental consequences a hazardous liquid release could have on 
such waters.

Other Areas

    EPA Region III maintained that product specific differences should 
be incorporated into the definition. Environmental Defense, Batten and 
other commenters wanted OPS to expand the definition of high 
consequences areas to include cultural, recreational, tribal and 
economic resources. Environmental Defense suggested we include national 
parks, wilderness areas, and wildlife refuges.

[[Page 75391]]

The City of Bellingham asked that we consider addressing integrity 
management programs for pipeline located outside the high consequence 
areas.
    The City of Austin commented that the definition failed to include 
areas that are of high consequence due to preservation or recreational 
value alone. The City suggested including all state, national, and 
local parkland, refuges and wilderness areas, and preserves designated 
for water quality protection and wildlife.
    API argued against expanding the definition to include cultural 
resources, environmental resources other than those identified as USAs, 
and other areas of national importance. They argued that including 
these areas would dilute available resources and focus from the 
populated and environmental areas that need greater protection, and 
that many other Federal, state, and local regulations are in place to 
minimize the effects of hazardous liquid pipelines on these other 
areas.
    During discussions with representatives from DOJ/ENRD, DOI, and 
EPA, we were strongly urged to include other areas as high consequence 
areas: all waters of the United States, wetlands and wildlife refuges, 
wilderness areas, fish hatcheries, units of the National Park System, 
and wild and scenic rivers. DOI, DOJ and EPA strongly recommended that 
the National Parks and National Fish Hatcheries be included in the 
definition.

Identification of High Consequence Areas

    API and liquid operators wanted OPS to clarify its commitment to 
identify high consequence areas, to generate and publish maps of the 
areas, and to periodically update the maps. These commenters said that 
such information was necessary before operators could assess pipelines 
and take appropriate preventive and mitigative measures.
    Response: The final rule continues to focus on areas where we have 
determined a hazardous liquid pipeline failure could pose the greatest 
threat to public safety, unusually sensitive environmental areas 
(including drinking water and ecological resources), and water commerce 
that is essential for communities' safety and public health or for 
national security. We have not revised the definition to incorporate 
product-specific differences; rather, other parts of the rule address 
the risks associated with different products the pipeline is 
transporting (e.g., when considering risk factors for establishing 
assessment intervals).

Populated Areas

    In the final rule, we have not changed the definition of populated 
ares that is based on the Census Bureau's definitions and delineations. 
We disagree that we misstated the Census Bureau's definition of 
urbanized areas. The only change we have made is in the terms we are 
using. What Census Bureau calls an urbanized area, we are calling a 
high population area. The additional populated areas that the Census 
Bureau calls a census designated place, we are calling an other 
populated area. We have chosen these definitions to avoid confusion 
over the term places, which the Census Bureau used to include both 
urbanized and census designated places. Our National Pipeline Mapping 
Systems (NPMS) will use the same titles and definitions used in this 
final rule.
    We are using Census Bureau data for the population component 
because it is the recognized expert and source for general population 
data in the communities of the United States. The data are 
standardized, publicly available and in a format that allows OPS and 
others to create maps of the populated areas. OPS currently does not 
have the resources to gather local data on utility connections. 
However, nothing precludes an operator from supplementing the maps we 
will provide with other data pertinent to its pipeline. (As discussed 
later in this Preamble under the sub-topic heading ``Identification of 
high consequence areas'', an operator will have the ongoing 
responsibility to incorporate newly-identified populated areas and 
unusually sensitive environmental areas into its assessment plan.)
    Populated areas consist of high population and other populated 
areas. High population areas are the Census Bureau's urbanized areas. 
These areas contain 50,000 or more people and have a population density 
of at least 1,000 people per square mile. Other populated areas are the 
Census Bureau's places minus the urbanized areas. These areas contain 
concentrations of people and include incorporated or unincorporated 
cities, towns, villages, or other designated residential or commercial 
areas.
    We believe the population component of the high consequences area 
definition picks up most areas where pipelines can pose a threat to 
public safety. However, we are aware that there may be other areas 
where people congregate near pipelines, but do not fall within either 
sub-component of the population definition. Two recent and tragic 
accidents illustrate the dangers that pipelines pose to public safety 
in these areas. In Bellingham, Washington, a pipeline release into a 
creek ignited and resulted in the deaths of three young people who were 
in the recreational park through which the creek flowed. An explosion 
that occurred on one of the three adjacent large natural gas pipelines 
near Carlsbad, New Mexico, killed 12 people, including five children, 
who had been camping near the pipeline.
    Although this rule is not including areas where people congregate 
in the high consequence area definition, OPS is considering addressing 
these areas in a future rulemaking. In the meantime we encourage 
operators to consider addressing in their integrity management programs 
areas where people congregate and to determine if there are pipeline 
segments in or near these areas that could affect the area. Operators 
should be able to recognize these areas, through fly overs or other 
surveillance made of their pipelines, or through consultation with 
local officials in the community.

USAs

    The rule's definition of high consequence areas will incorporate 
the final definition of Unusually Sensitive Areas, which OPS expects to 
issue in November 2000 (Docket No. RSPA-99-5455). The USA rulemaking 
will address the resolution of the above comments and other submitted 
to the docket for that rulemaking. Because of the dependence of this 
rulemaking on the final definition of USAs, this rule will not be 
effective until March 31, 2001.

Commercially Navigable Waterways

    Our inclusion of commercially navigable waterways for public safety 
and secondary reasons is not based on the ecological sensitivity of 
these waterways. Parts of waterways sensitive for ecological purposes 
are covered in the proposed USA definition, to the extent that they 
contain occurrences of a threatened and endangered species, critically 
imperiled or imperiled species, depleted marine mammal, depleted multi-
species area, Western Hemispheric Shorebird Reserve Network or Ramsar 
site. In this rule, only those pipeline segments that could affect a 
commercially navigable waterway are covered. We are including 
commercially navigable waterways as high consequence areas because 
these waterways are a major means of commercial transportation, are 
critical to interstate and foreign commerce, supply vital resources to 
many American communities, and are part of

[[Page 75392]]

a national defense system. A pipeline release could have significant 
consequences on such vital areas by interrupting supply operations due 
to potentially long response and recovery operations that occur with 
hazardous liquid spills. As explained later, OPS will map these 
waterways on its National Pipeline Mapping System.

Other Areas

    As discussed above, representatives of several Federal government 
agencies urged us to include other areas in the definition of high 
consequence areas. We have decided not to include these suggested areas 
in this rulemaking.
    Although we have not included the other suggested areas in this 
rulemaking, we are considering extending protection to other 
environmentally sensitive and vital resources through future 
rulemaking. Other areas that will be considered include National Parks, 
National Wildlife Refuges, National Wilderness Areas, National Forests, 
and other cultural resources and sensitive environmental resources that 
do not meet the USA filtering criteria.

Identification of High Consequence Areas

    OPS will identify high consequence areas on its National Pipeline 
Mapping System (NPMS). Operators, other government agencies and the 
public will have access to these maps through the Internet. Individuals 
will be able to view high consequence areas nationally or by state, 
county, zip code, or zooming in or out of a particular area. An 
operator will then be able to determine which of its pipeline segments 
intersect or have the ability to affect a high consequence area.
    OPS will identify the locations of USAs through a comprehensive 
collection and analysis of drinking water and ecological resource data, 
contingent on the availability of funding and resources.\3\ OPS will 
make its USA maps, including the drinking water data, available through 
the National Pipeline Mapping System. Barring unforeseen resource 
demands, OPS's current plan is to have the USAs in the top ten states 
(covering 75% of total pipeline mileage) available by the end of 
December 2000. Maps of the USAs in the next ten states (90% of total 
pipeline mileage) should be available by April 2001. And we plan to 
have the maps of the remaining states (100% of total pipeline mileage) 
available by December 2001.
---------------------------------------------------------------------------

    \3\ OPS uses state data bases as the primary data source for the 
USA model. The drinking water USA model relies on data solely 
provided by the States. State aquifer maps are used to determine 
aquifer classifications. State data on well location depth, and 
source are used to identify the aquifers used by the wells. The 
ecological USA model uses data from the state Natural Heritage 
Programs (NHP) on rare and endangered species locations. OPS is also 
using the Environmental Sensitivity Index and related ecological 
data sets to augment the NHP data.
---------------------------------------------------------------------------

    Some of the information that OPS is purchasing, such as discrete 
sets of ecological data from the Nature Conservancy and other sources, 
will not be publicly available. Operators may need to contact resource 
agencies to obtain additional information on a particular species or 
drinking water intake in an USA.
    OPS will use the National Waterways Network database to identify 
commercially navigable waterways. The commercially navigable waterways 
map and database will be available through the National Pipeline 
Mapping System. The Bureau of Transportation Statistics also has a 
database that includes commercially navigable waterways and non-
commercially navigable waterways. The database can be downloaded from 
the BTS website: http://www.bts.gov/gis/ntatlas/networks.html.
    OPS will use the Census Bureau's data to identify high population 
and other populated areas. We will use the Census Bureau's urbanized 
area data to identify high population areas and their places data to 
identify other populated areas. Their data on places includes both 
urbanized areas and other populated areas. OPS will filter out the 
urbanized areas data from the places data so that the resulting map and 
database will clearly distinguish other populated areas from the 
urbanized or high population area data. Operators and the public will 
be able to view the high population and other populated areas maps 
together or separately on the National Pipeline Mapping System.
    OPS recognizes that inventories and maps of high consequence areas 
have to be updated on a periodic basis to incorporate new information 
and databases. OPS intends to update the high consequence area maps 
every five years, contingent on the availability of funding and 
resources. OPS will review new or revised programs and databases at 
that time to incorporate appropriate programs and databases into the 
high consequence area definition and model. OPS will announce in the 
Federal Register and through other communication networks when revised 
high consequence area maps are available for given areas.
    Changes, particularly population changes, will occur around an 
operator's pipeline. Although OPS intends to periodically update the 
maps, it remains an operator's responsibility to keep information about 
its pipelines up to date. By continually evaluating its entire pipeline 
and analyzing all available information about the integrity of the 
pipeline, an operator should be aware of population and ecological 
changes that are occurring around the pipeline and continue to update 
its maps and integrity management program to accommodate these changes.
    In the rule we have added requirements about how an operator is to 
incorporate any newly-identified high consequence areas into its 
baseline assessment plan and integrity program. The rule provides that 
when an operator has information (from the information analysis or from 
Census Bureau maps) that the population density around a pipeline 
segment has changed so as to fall within the definition of a high 
population area or other populated area, the operator must incorporate 
the area into its baseline assessment plan as a high consequence area 
within one year from the date the area is identified. Similarly, an 
operator must incorporate a new unusually sensitive environmental area 
into its plan within one year from the date the area is identified. The 
rule further requires an operator to complete the baseline assessment 
of any line pipe that could affect the newly-identified high 
consequence area within five years from the date the area is 
identified.
    We thought it necessary to add these requirements because of the 
concerns many commenters expressed about who would be responsible 
identifying high consequence areas and how updates would be handled. 
Although OPS is taking primary responsibility for mapping these areas, 
an operator has a corresponding responsibility to continually evaluate 
its pipeline and update information about the pipeline.
8. Requirements for Preventive and Mitigative Measures, Including, 
Emergency Flow Restricting Devices (EFRDs) and Leak Detection Systems--
Proposed Section 195.452(i)
    The proposed rule required an operator to conduct a risk analysis 
to assess the risks to its pipeline system and determine what 
additional preventive and mitigative measures are needed to protect a 
high consequence area. The proposal identified possible preventive or 
mitigative measures an operator could take to protect a high 
consequence area, such as implementing damage prevention best 
practices, establishing or modifying leak detection systems, and 
providing additional training on response procedures.

[[Page 75393]]

    Installing EFRDs was one of several mitigative measures the rule 
proposed. However, the proposal did not require an operator to install 
EFRDs or define the conditions under which an operator should install 
EFRDs. In the NPRM we specifically invited comment on any needed 
further guidance to operators on when EFRDs should be installed. We 
also invited comment on the criteria for evaluating the decision on 
whether to install an EFRD or to take other measures, and if in certain 
limited circumstances, we should mandate the use of EFRDs.
    EPA Region III supported the preventive and mitigative measures the 
rule proposed but argued against leaving the need for particular 
actions to the operator. Region III was concerned that without active 
and knowledgeable regulatory oversight, strict methodology, or the 
required participation of a risk assessment professional, an operator 
would be unlikely to find any of the measures necessary. Environmental 
Defense said that the rule should include specific requirements for 
operators to use preventive strategies. NTSB expressed concern with 
operators using risk management principles to determine the need for 
additional protective measures and recommended that the rule include 
minimum criteria.
    EPA Oil Program Center said that the rule should prescribe 
circumstances in which EFRDs or other protective and mitigative 
measures must be used. EPA Oil Programs further commented that if the 
rule allows an operator to conduct a risk assessment to determine if 
EFRDs or other protective measures are needed, then the rule should 
prescribe a specific risk assessment protocol.
    Environmental Defense, Batten and other advocates recommended that 
the rule include performance standards for leak detection, EFRD spacing 
and damage prevention best practices. Environmental Defense and 
Pipeline Survivor's Association recommended that leak detection systems 
be capable of detecting a leak of one gallon/minute or more and that 
EFRD spacing prevent releases of more than 10,000 gallons of hazardous 
liquid into a high consequence area. The City of Austin supported 
requiring EFRDs in all high consequence areas and that they be spaced 
to restrict the worst case spill to 10,000 gallons. Batten suggested 
that leak detection devices be capable of detecting within 15 minutes a 
leak of ten gallons or more and that pipe segments between EFRDs be 
able to contain no more than 50,000 gallons when located in a high 
consequence area.
    AWWA encouraged the placement of EFRDs to the greatest extent 
possible to protect public water supplies, suggesting that EFRDs be 
used as the standard against which other mitigation strategies are 
measured. LCRA commented that EFRDs should be required on either side 
of a river crossing. EPA Region III also encouraged using EFRDs 
whenever necessary to protect a high consequence area.
    API and operators commented that the proposed rule is reasonable 
and that OPS should ensure risk mitigation decisions made within an 
integrity management program include considering the use of EFRDs 
rather than requiring such placement or prescribing minimum spacing. 
Enbridge and Lakehead supported EFRDs as one of various preventive or 
mitigative actions an operator should consider but said there was no 
one distance or placement specification appropriate for all pipeline 
systems. Many cited research by the California State Fire Marshall, and 
Southwest Research to support their argument that there are many site 
and flow-specific factors that operators must consider in making risk 
mitigation decisions. Several industry commenters also noted the 
possible environmental disadvantage to EFRDs, including the possibility 
of valve leakage or inadvertent closure resulting in over 
pressurization, as well as the environmental impacts of installing and 
maintaining valves in or near environmentally sensitive areas.
    Response: The final rule continues to require an operator to take 
additional measures to prevent and mitigate the consequences of a 
pipeline failure that could affect a high consequence area. It is up to 
each operator to conduct a risk analysis of the pipeline segment to 
identify additional actions to enhance public safety or environmental 
protection. For this risk analysis, the rule clarifies that an operator 
must evaluate the likelihood of a pipeline release occurring, how a 
release could affect the high consequence area, and what risk factors 
the operator should consider. The rule continues to list some 
additional preventive and mitigative measures an operator should 
consider. The list is not an exhaustive recitation of every preventive 
or mitigative measure that could enhance public safety or environmental 
protection.
    One of the listed measures is for an operator to modify the systems 
that monitor pressure and detect leaks. Operators use various 
procedures and methods to detect the movement of product through the 
pipeline. For example, computational pipeline monitoring, SCADA 
systems, and station sensors, measure deviations from measured values 
(pressures, flows) beyond established norms. The pipeline safety 
regulations do not require an operator to have a leak detection system. 
However, if an operator has a software-based leak detection system, the 
regulations require the operator to use an industry document (API 1130) 
in designing, evaluating, operating, maintaining and testing its 
software-based system. (See Sec. 195.444.) Moreover, whenever a leak 
detection system is installed or a component replaced, API 1130 must be 
followed.
    The final rule requires an operator to have a means to detect leaks 
on its pipeline system. (We provide several examples of types of leak 
detection systems later in this document when we discuss Section 
195.452(i).) We have re-written the rule to require an operator to 
evaluate the leak detection's capability to protect the high 
consequence area and to modify, as needed, to protect the high 
consequence area. The rule includes factors that an operator must 
consider in making its evaluation. OPS enforcement personnel will 
review the adequacy of this evaluation process during site inspections.
    Another protective measure the rule identifies is for an operator 
to install an EFRD on the pipeline segment. The final rule does not 
prescribe the specific conditions under which EFRDs or other preventive 
or mitigative measures are required. Rather, the final rule requires an 
operator to develop and apply risk assessment and decision-making 
processes that reflect pipeline-specific conditions and operating 
environments. The rule now specifies criteria that an operator must 
consider when conducting the analysis to identify additional protective 
measures. An operator is not limited to these criteria; rather, an 
operator must consider these criteria in addition to all other criteria 
specific to the pipeline segment.
    In the final rule, OPS has not specified the circumstances when an 
operator must use a particular protective measure or install an EFRD. 
However, we have revised the rule to require that an operator install 
an EFRD if the operator determines that one is needed to protect the 
high consequence area. The rule also specifies factors that an operator 
must consider in making this determination. OPS will review during 
inspection the adequacy of the analysis and the appropriateness of the 
operator's decision on the need to install an EFRD.

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    OPS has been studying for some time the issue of the optimum 
placement of emergency flow restricting devices to limit commodity 
release after the location of the release has been identified. In the 
NPRM, we explained in detail the research OPS has conducted in this 
area. (See 65 FR 21695; April 24, 2000.) In addition to comment the 
NPRM solicited, OPS had previously issued an advance notice of proposed 
rulemaking asking questions concerning the performance of leak 
detection equipment and location of EFRDs, and held a public workshop 
to discuss the issues involved in developing regulations on EFRDs.
    Our study of the issue led us to conclude that the decision to 
install an EFRD should not be mandatory but should be left to the 
operator. Nonetheless, the rule requires an operator to consider 
certain specified criteria in deciding whether an EFRD will protect the 
high consequence area.
    OPS is requiring an operator to determine whether to install an 
EFRD based on the operator's risk analysis, because, we believe, 
prescriptive valve installation and spacing requirements would ignore 
the site-specific variables and unique flow characteristics of a 
pipeline segment. Prescriptive requirements could also overlook the 
potential sensitivity of a specific high consequence area. For example, 
locating an EFRD near a body of water to reduce the potential volume 
released might necessitate locating the valve in sensitive wetlands or 
a flood plain of a river, which creates myriad other problems. Also, a 
prescriptive approach detracts from the process of evaluating a host of 
alternative measures to enhance protection to high consequence areas.
9. Methods To Measure Program's Effectiveness--Proposed Section 
195.452(k)
    In the NPRM we proposed that an operator's integrity management 
program include methods to measure whether the program is effective in 
assessing and evaluating the integrity of the pipelines and in 
protecting the high consequences areas. NTSB commented that this 
requirement has to contain unequivocal guidance if operators are to use 
it to improve their programs, and suggested that we develop measures. 
EPA Region III commented that a measurement based on some industry-wide 
average should not be used because it could lower the bar for 
management, technology, and innovation.
    Response: We have not revised the provision on program performance 
measures other than to clarify that an operator is to measure the 
effectiveness of the program on each pipeline segment. In Appendix C we 
have described types of program measures and included examples of 
methods that an operator can use to evaluate the effectiveness of its 
integrity management program.
10. Cost Benefit Analysis
    The comments we received on the proposed rule's cost benefit 
analysis are addressed below under the Regulatory Analyses and Notices 
section.
11. Information for Local Officials and the Public
    In the NPRM, OPS invited comments on how local officials could use 
and benefit from risk assessment information, how the consequences of 
potential pipeline failures should be characterized, how risk control 
actions should be described and what performance indicators would be 
meaningful. We further said that because of the significance of this 
issue we planned on extensive discussions with all the stakeholders 
before proposing communications requirements as part of an integrity 
management program.
    Many provided comments relevant to the issue of communications with 
local officials. Tosco agreed that research is needed on the types and 
amount of information to distribute to local officials and made 
available to the general public to determine the most effective means 
to keep those entities informed. Environmental Defense, the Pipeline 
Survivor's Association, and Batten listed information they thought 
operators should make available to public officials and the public. 
American Water Works Association strongly supported the need for 
communication, but provided no specific guidance on content.
    Lower Colorado River Authority (LCRA) promoted public involvement 
in the preparation and implementation of integrity management programs, 
maintaining that with public involvement, pipeline operators would have 
a better understanding of the vulnerability of the resources. LCRA 
further commented that public confidence in the pipeline industry would 
be enhanced if the results of the integrity assessments were made 
available. The City of Bellingham also recommended that integrity 
management programs be developed in consultation with appropriate state 
and local officials before the operator finalizes the program. The 
National Pipeline Reform Coalition also recommended that local 
communities have a role in developing the programs, citing the evidence 
of the role of the City of Bellingham in developing a safety plan for 
Olympic Pipe Line Company.
    Response: Requirements for communication of integrity management 
information to local public officials and to the public will be the 
subject of a future rulemaking. We will use the comments received in 
this rulemaking in developing the communications rulemaking. A 
communications work team, consisting of representatives from 
environmental and public safety organizations, pipeline companies, and 
government has formed to aid the Hazardous Liquid Advisory Committee 
(THLPSSC) in developing communications issues. Notices of meetings of 
the work group will be published in the Federal Register. Notes from 
the meetings will be posted on OPS's web site.
12. Appendix C Guidance
    Proposed Appendix C provided operators guidance on how to 
prioritize risk factors in determining assessment frequency, how to 
analyze smart pig inspection results, how to prioritize metal loss 
features, and what types of smart pigs to use for finding pipeline 
anomalies. The proposed Appendix also included risk indicator tables 
for leak history, volume or line size, age of pipeline, and product 
transported, to help determine if the pipeline segment falls into a 
high, medium or low risk category.
    There were a variety of comments concerning Appendix C. Some 
addressed the role of Appendix C in the overall rule, and others 
provided specific technical comments on detailed aspects of the 
Appendix (which are not summarized here).
    API and other liquid operators commented that Appendix C ``is not 
sufficiently rigorous or technically accurate to be used as guidance 
for prioritizing risk'' and provided a list of problems they have 
identified. API recommended that OPS not include the Appendix in the 
final rulemaking, but that OPS and the integrity standard work group 
develop technically accurate, rigorous guidance for prioritizing risk 
factors.
    The City of Austin recommended that Appendix C be included as part 
of the rule because it specifies how an operator should implement the 
proposed regulation. Fuel Safe Washington stated that ``Appendix C is 
completely undermined by allowing operators to apply their own weights 
or values to the risk factors.''

[[Page 75395]]

    Response: An Appendix is guidance that is intended to give advice 
to operators on how to implement the requirements of the integrity 
management rule. An Appendix does not have the same force as the 
regulation itself. An operator does not have to follow the guidance. 
However, if an operator incorporates parts of the Appendix into its 
integrity management program, an operator must then comply with those 
provisions.
    OPS continues to believe that the guidance provided in Appendix C 
will be helpful to operators in developing and implementing their 
integrity management programs. (Operators may supplement this guidance 
with the industry consensus standard or choose not to use the 
guidance.) We also continue to believe that the guidance should not be 
included in the body of the rule because it would unnecessarily inhibit 
operators from identifying the best pipeline- and segment-specific 
tools, risk factors, and repair techniques, and would require changes 
in the rule as new technologies or information is developed.
The Final Rule
    The new section 195.450 titled ``Definitions'' defines high 
consequence areas. High consequence areas include--
     Unusually sensitive areas--these areas will be defined in 
the USA rulemaking (Docket No. RSPA-99-5455) and will include drinking 
water and ecological resources;
     High population areas--these are areas defined and 
delineated by the Census Bureau as urbanized areas.
     Other populated areas--these are areas defined and 
delineated by the Census Bureau as places that contain a concentrated 
population.
     Commercially navigable waterways--these are waterways 
where a substantial likelihood of commercial navigation exists.
    The integrity management program requirements will apply to 
pipeline segments that could affect these high consequence areas. OPS 
will map these areas on its National Pipeline Mapping System, and make 
the maps publicly available.
    This section also defines emergency flow restricting devices to 
include check valves and remote control valves. This definition is used 
in Sec. 195.452(i) of the rule that addresses additional preventive and 
mitigative measures an operator must consider for pipeline segments 
that could affect a high consequence area.
    The new section 195.452 titled ``Pipeline Integrity Management in 
High Consequence Areas'' imposes integrity management program 
requirements on each operator who owns or operates a total of 500 or 
more pipeline miles used in hazardous liquid transportation.
    For an operator covered by the rule, the rule requires the operator 
to develop, implement and follow an integrity management program that 
provides for continually assessing the integrity of those pipeline 
segments that could affect a high consequence area, through internal 
inspection, pressure testing, or other equally effective assessment 
means. An operator's program must also provide for evaluating the 
segments through comprehensive information analysis, remediating 
potential integrity problems found through the assessment and 
evaluation, and ensuring additional protection though preventive and 
mitigative measures.
    Through this required program, a hazardous liquid operator must 
comprehensively evaluate the entire range of threats to each pipeline 
segment's integrity by analyzing all available information about the 
entire pipeline and its relevance to the segment that could affect a 
high consequence area. Information an operator must evaluate includes 
information on the potential for damage due to excavation; data 
gathered through the required integrity assessment; results of other 
inspections, tests, surveillance and patrols required by the pipeline 
safety regulations, including corrosion control monitoring and cathodic 
protection surveys; and information about how a failure could affect 
the high consequence area.
    The final rule requires an operator to take prompt action to 
address all integrity issues raised by the integrity assessment and 
information analysis. This means an operator must evaluate all 
anomalies and repair those could reduce a pipeline's integrity. An 
operator must develop a schedule that prioritizes the anomalies for 
evaluation and repair. The schedule must include time frames for 
promptly reviewing and analyzing the integrity assessment results and 
completing the repairs. An operator must also maintain, and further 
protect the integrity of these pipeline segments, through other 
remedial actions, and preventive and mitigative measures.
Which Operators Must Comply? Section 195.452(a)
    This rule specifies pipeline system integrity management program 
requirements for each operator who owns or operates a total of 500 or 
more miles of hazardous liquid pipeline. This action covers 
approximately 87 percent of all the hazardous liquid pipelines in the 
United States. Based on the volume of hazardous liquid these pipelines 
transport, they have the greatest potential to adversely affect the 
environment.
    For an operator covered by this rule, the requirements apply to all 
the operator's pipeline segments (offshore or onshore), regardless of 
date of construction, that could affect a high consequence area. The 
rule specifies how operators must provide additional protection to 
critical areas (i.e., high consequence areas) through integrity 
management programs. Further, it assures that these protections will be 
put in place, with an operator being required to initially assess 50 
percent of the line pipe that could affect critical areas, beginning 
with the highest risk pipe, within 3.5 years and the balance within 
seven years. An operator will then have to evaluate and repair defects 
within specified time frames and implement additional preventive and 
mitigative measures. An operator is also required to continually re-
assess its pipeline segments at intervals not longer than five-years, 
as well as periodically evaluate each pipeline segment by analyzing all 
available information about the integrity of the entire pipeline, and 
its relevance to segments that could affect the high consequence areas.
What Must an Operator Do? Section 195.454(b)
    The rule requires that, no later than one year after the rule's 
effective date, an operator must develop a written integrity management 
program that addresses the risks on each pipeline segment that could 
affect a high consequence area. An operator must then implement and 
follow the program it has developed. Initially, the program will 
consist of a framework. An operator must include in its integrity 
management program--
     An identification of all pipeline segments that could 
affect a high consequence area. Because identification of the pipeline 
segments is the trigger for all other integrity management 
requirements, the identification must be done within nine months from 
the rule's effective date.
     A plan for baseline assessment. The assessment of the line 
pipe must be done by internal inspection, pressure test, or other 
technology that provides an equivalent understanding of the condition 
of the line pipe.
     A program framework that addresses each of the required 
program elements, including continual integrity assessment and 
evaluation. In the first year after the rule's effective date, the

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framework must indicate how decisions will be made to implement each 
required program element. The framework will evolve into an integrity 
management program as the operator makes decisions and gains 
experience. An integrity management program is a dynamic program that 
an operator must continually change as the operator gains more 
information about the pipeline and the results of the assessments.
    To carry out the rule's requirements, an operator must follow 
recognized industry practices unless the rule specifies otherwise or 
the operator chooses an alternative practice that is supported by a 
reliable engineering evaluation and provides an equivalent level of 
public safety and environmental protection. Recognized industry 
practices include national consensus standards and practices found in 
reference guides. Allowing the use of alternative practices in the rule 
should encourage operators to use innovative technology in implementing 
the integrity management program's requirements.
What Must Be in the Baseline Assessment Plan? Section 195.452(c)
    The rule requires an operator to include in its written baseline 
assessment plan each of the following elements.
     The methods selected to assess the integrity of the line 
pipe of each segment that could affect a high consequence area;
     A schedule for completing the integrity assessment;
     An explanation of the assessment methods the operator 
selected and an evaluation of risk factors the operator considered in 
establishing the assessment schedule for the pipeline segments.
    The rule allows an operator to modify the baseline assessment plan 
provided the operator documents the modifications and reasons for the 
modifications. As discussed later under the section on recordkeeping 
requirements (Sec. 195.452(l)), these are documents an operator is 
required to maintain for inspection. Enforcement personnel will look to 
see that an operator has documented the modification well before the 
operator has implemented the modification.
    OPS expects an operator to make the best use of current and 
innovative technology in assessing the integrity of the line pipe. 
Therefore, the rule allows an operator to conduct an integrity 
assessment by--
     Internal inspection tool or tools capable of detecting 
corrosion and deformation anomalies including dents, gouges and 
grooves. For electric resistance welded (ERW) pipe or lap welded pipe 
susceptible to longitudinal seam failures, the rule provides that the 
integrity assessment methods must be capable of assessing seam 
integrity and of detecting corrosion and deformation anomalies. An 
operator's program would also have to address any risk factors 
associated with these types of pipe;
     Pressure test conducted in accordance with Part 195, 
subpart E; or
     Other technology that provides an equivalent understanding 
of the condition of the line pipe.
    Internal inspection is one of the most useful tools in an integrity 
management program. We expect an operator to consider at least two 
types of internal inspection tools for the integrity assessment of the 
line pipe: geometry pigs for detecting changes in circumference and 
metal loss tools (magnetic flux leakage (MFL) pigs or ultra sonic pigs) 
for determining wall anomalies, or wall loss due to corrosion. Both 
high resolution and low resolution tools can be beneficial in integrity 
assessment. For example--
    Corrosion/metal loss: With respect to corrosion, high-resolution 
tools can identify anomalies and, with the use of engineering critical 
assessments, use a conservative evaluation of the potential for the 
anomaly to have affected remaining pipe strength (or affected the 
pressure capacity of the pipeline segment). This assessment uses 
analytical techniques that estimate average depth of metal loss. Based 
on the evaluation of internal inspection results, a prioritized listing 
of potential defects is developed to guide the initiation of the field 
digging, inspection, confirmation and the necessary repair program. 
Once in the field, additional calculations based on actual profile of 
metal loss are used to confirm the need and type of appropriate repair.
    High Resolution versus Low Resolution: High-resolution tools can 
distinguish between internal and external corrosion and provide more 
extensive information to more accurately assess the potential for an 
anomaly to pose a risk.
    Mechanical Damage: Internal inspection tools to measure dents or 
geometric deformations are common and are typically run routinely 
following installation of new pipelines. Technology has advanced such 
that geometry tools can normally withstand even the most extreme 
pipeline conditions. The tool is able to pass restrictions (e.g., 
deformations) of up to 25%, and with the high sensitivity of gauging 
systems now on the market and large number of sensing fingers, current 
tools can detect even very small ovalities (0.6%).
    Crack Detection: Since the early 1990's, pipeline operators have 
successfully field tested internal inspection tools capable of non-
destructively identifying fatigue cracks and stress corrosion cracking 
in the longitudinal seam. Research and development continues on these 
tools to strive for reliable identification of other types of seam 
defects, such as hook cracks. With the use of ultrasonic and MFL 
(transverse orientation) technology, pipeline segments that have 
experienced fatigue cracking can now be inspected. Cracks with a 
potential to rupture can be identified and repaired prior to growing to 
a critical stage. This is particularly important as this type of defect 
could survive initial and subsequent pressure tests but then with 
pressure cycling, grow over time to a critical stage and leak or 
rupture.
    The rule also permits integrity assessment of the line pipe by 
pressure test. An operator must conduct a pressure test according to 
the requirements prescribed in Part 195, subpart E.
    The purpose of a pressure test is to remove defects that might 
impair the integrity of the pipeline during operation. Defects might 
exist as a result of the manufacturing process or damage to the pipe 
during shipping, construction or operation. The defects are identified 
by failure of the pipe during the test, the defective pipe is removed, 
new pipe is installed, and the pipe is tested again until no failure 
occurs. The pressure test provides a margin of safety for the pipeline 
by being conducted at a pressure higher than the maximum pressure at 
which pipeline safety regulations allow the pipeline to be operated.
    OPS expects that an operator choosing this method of integrity 
assessment for a pipeline segment will review its corrosion control 
monitoring program for that segment. OPS inspectors will review these 
documents when evaluating an operator's choice of pressure test as an 
assessment method.
    To encourage innovation, the final rule also allows an operator to 
use other technology for the integrity assessment, if the operator 
demonstrates that an alternative technology can provide an equivalent 
understanding of the condition of the line pipe as the other permitted 
assessment methods.
    An operator choosing this option must notify OPS at least 90 days 
before conducting the assessment with the other technology. The rule 
specifies

[[Page 75397]]

how notification can be made: by mail or facsimile. Advance notice is 
necessary so that OOPS enforcement personnel have adequate time to 
review the operator's basis for using the technology.
When Must the Baseline Assessment Be Completed? Section 195.452(d)
    The rule requires an operator to establish a baseline assessment 
schedule to determine the priority for assessing the pipeline segments 
covered by the rule. An operator must complete the baseline integrity 
assessment within seven years after the rule's effective date. An 
operator is further required to assess at least 50% of the covered line 
pipe, beginning with the highest risk pipe, within 3.5 years from the 
rule's effective date. This requirement, in conjunction with the 
requirement to base the assessment intervals on risk-based factors, 
should ensure that an operator assesses the highest risk pipeline 
segments earlier in the cycle.
    The final rule allows an operator to use an integrity assessment 
method conducted five years before the rule's effective date as the 
baseline assessment if the method is at least equivalent to the 
requirements for internal inspection, pressure testing or alternative 
technology. However, if an operator decides to use a prior integrity 
assessment as its baseline assessment, the operator must then re-assess 
the integrity of the line pipe within five years. The re-assessment 
would have to comply with the continual integrity assessment 
requirements in Sec. 195.452(j). As we discuss later in this document 
when explaining Sec. 195.452(j), the rule allows for deviations from 
the five-year requirement in certain limited instances.
    Because population and ecological changes may occur around an 
operator's pipeline, an operator must, as part of its periodic 
evaluation and information analysis, keep informed about how such 
changes are affecting each pipeline segment. If the population density 
around a pipeline segment changes so as to fall within the definition 
of a high population area or another populated area, the rule requires 
an operator to incorporate the area into its baseline assessment plan 
as a high consequence area. This must be done within one year from when 
the area is identified. An operator must then assess the integrity of 
any line pipe that could affect that newly identified high consequence 
area within five years from when the area is identified. Similarly, the 
rule requires an operator to incorporate a new unusually sensitive 
environmental area into its baseline plan within one year from when the 
area is identified and to assess the new area within five years.
What are the Risk Factors for Establishing an Assessment Schedule? 
Section 195.452(e)
    For both the baseline and continual integrity assessments, an 
operator must establish a schedule that prioritizes the pipeline 
segments for assessment so that the higher risk segments are assessed 
earlier in the cycle. The rule requires an operator to base the 
assessment schedule on all risk factors that reflect the risk 
conditions on each pipeline segment. The rule further specifies some 
factors an operator must consider in establishing a schedule. An 
operator is not limited to these factors; rather, an operator must 
supplement the listed factors with those that are specific or unique to 
the pipeline segment being assessed.
    In Appendix C, we provide guidance to an operator on how to 
determine risk factors for a pipeline segment and use them to develop 
an integrity assessment schedule. The guidance includes an example of 
risk factors that we apply to a hypothetical pipeline segment to 
establish an assessment frequency.
What Are the Elements of an Integrity Management Program? Section 
195.452(f)
    The final rule requires an operator to include certain minimum 
elements in its integrity management program. Initially, an operator 
must develop a framework containing these elements. The framework 
evolves into a program as the operator gains experience, makes 
decisions and implements actions. The required program elements 
include--
     A process for identifying which pipeline segments could 
affect a high consequence area. The Appendix gives guidance to help an 
operator evaluate how a pipeline segment could affect an area, which 
will help an operator in developing this process. The guidance lists 
factors an operator needs to consider when evaluating the pipeline 
segment's ability to affect a high consequence area.
     A baseline assessment plan (discussed in Sec. 195.452(c));
     An analysis that integrates all available information 
about the integrity of the entire pipeline, its relevance to the 
particular segment, and the consequences of a failure;
     Criteria for repair actions to address integrity issues 
raised by the assessment methods and information analysis;
     A continual process of assessment and evaluation to 
maintain a pipeline's integrity;
     Identification of preventive and mitigative measures to 
protect the high consequence area;
     Methods to measure the program's effectiveness; and
     A process for review of integrity assessment results and 
information analysis by a person qualified to evaluate the results and 
information. An operator must use qualified persons with the necessary 
technical expertise to evaluate and analyze the results and data from 
the integrity assessments, the periodic evaluation, the information 
analyses, etc.
    To be effective, an integrity management program must constantly 
change. OPS expects that the initial program will consist of a 
framework that specifies the criteria for making decisions to implement 
each of the required elements. The program evolves from the framework 
and must continue to change to reflect operating experience, 
conclusions drawn from results of the integrity assessments, and other 
maintenance and surveillance data, and evaluation of consequences of a 
failure on the high consequence area.
What is an Information Analysis? Section 195.452(g)
    The final rule requires an operator to periodically evaluate the 
integrity of each pipeline segment that could affect a high consequence 
area by analyzing all available information about the integrity of the 
entire pipeline and the consequences of a failure. The analysis applies 
to the entire pipeline to determine the relevance to a particular 
pipeline segment. Required information an operator must evaluate 
includes--
     Information critical to determining the potential for, and 
preventing, damage due to excavation, including current and planned 
damage prevention activities, and development or planned development 
along the pipeline segment;
     Data gathered through the required baseline and continual 
integrity assessments;
     Data gathered in conjunction with other inspections, 
tests, surveillance and patrols required in Part 195. This would 
include information from corrosion control monitoring and cathodic 
protection surveys;
     Information about how a failure would affect the high 
consequence area, such as location of the water intake.
    Through this requirement to integrate and analyze information from 
diverse sources, OPS expects an operator to analyze its entire pipeline 
to evaluate the entire range of threats to each pipeline segment that 
could affect a high consequence area. An operator will

[[Page 75398]]

conduct this analysis in conjunction with the required periodic 
evaluation discussed below (section 195.452(j)).
What Actions Must Be Taken To Address Integrity Issues? Section 
195.452(h)
    The rule requires an operator to take prompt action to address all 
pipeline integrity issues raised by the integrity assessment and 
information analysis. By prompt action we mean that an operator must 
prioritize repairs according to the severity of the anomaly and address 
first those anomalies that pose the greatest risk to the pipeline's 
integrity. The rule clarifies that an operator must evaluate all 
anomalies and repair those that could affect the pipeline's integrity. 
Any repair made must be done according to the pipeline repair 
requirements in 49 CFR Sec. 195.422.
    The rule requires that an operator develop a schedule that 
prioritizes the anomalies found during the integrity assessment and 
information analysis for evaluation and repair. In this schedule, an 
operator would have to provide for prompt review and analysis of the 
integrity assessment results by a date certain. For the first three 
years after the rule's effective date, an operator would determine the 
period by which the results would have to be reviewed and analyzed and 
commit to that date in its schedule. After the third year, an 
operator's schedule must provide for reviewing and analyzing the 
results of the integrity assessment within 120 days of conducting the 
assessment.
    An operator's schedule also has to provide time frames for 
evaluating and completing repairs. The rule provides that an operator 
is to base the schedule on specified risk factors and pipeline-specific 
risk factors the operator develops. For conditions not specified in the 
rule and those the rule identifies as other conditions, the operator 
determines the schedule for evaluation and repair. However, the rule 
provides the time frames in which an operator must complete repair of 
certain conditions on the pipeline. These conditions are listed as 
immediate repair conditions, 60-day conditions and 6-month conditions. 
Of course, the rule cannot identify all conditions that an operator 
will have to evaluate and repair. A condition an operator discovers may 
qualify as an immediate repair, 60-day or 6-month condition even though 
it is not listed in the rule. The rule simply provides common examples 
of such conditions.
    The schedule required for repair starts at the time the operator 
discovers the condition on the pipeline, which occurs when an operator 
has adequate information about the condition to determine the need for 
repair. Depending on circumstances, an operator could have adequate 
information when the operator receives the preliminary internal 
inspection report, gathers and integrates information from other 
inspections or the periodic evaluation, excavates the anomaly or, 
receives the final internal inspection report.
    An operator may deviate from the rule's specified repair times 
(immediate repair, 60-day, 6-month) if the operator justifies the 
reasons why the schedule cannot be met and that 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. (See section 
195.452(l).) An operator must notify OPS if the operator cannot meet 
the schedule and cannot provide safety through a temporary reduction in 
operating pressure until a permanent repair is made. The operator would 
have to provide OPS 90-days notice by mail or facsimile.
What Preventive and Mitigative Measures Must an Operator Take To 
Protect the High Consequence Area? Section 195.452(i)
    The final rule requires an operator to take measures to prevent and 
mitigate the consequences of a pipeline failure that could affect a 
high consequence area. An operator must conduct a risk analysis of each 
pipeline segment to identify additional actions to enhance public 
safety or environmental protection. The rule lists some additional 
preventive or mitigative measures an operator needs to consider for the 
pipeline segment, including installing emergency flow restricting 
devices and modifying the leak detection systems. An operator is not 
limited to the listed measures but should also identify additional 
protective measures not listed.
    The rule requires that, in identifying the need for additional 
preventive and mitigative measures, the operator evaluate the 
likelihood of a pipeline release occurring and how a release could 
affect the high consequence area. An operator must consider all 
relevant risk factors in making this determination; the rule lists some 
that an operator must consider. An operator is to supplement the listed 
risk factors with any other factors specific or unique to the pipeline 
segment. Listed factors include--terrain surrounding the pipeline, 
including drainage systems such as small streams and other smaller 
waterways that could act as a conduit to the high consequence area; 
elevation profile; characteristics of the product transported; amount 
of product that could be released; possibility of a spillage in a farm 
field following the drain tile into a waterway; ditches along side a 
roadway the pipeline crosses; physical support of the pipeline segment 
such as by a cable suspension bridge; and exposure of the pipeline to 
operating pressure exceeding established maximum operating pressure. In 
addition, Appendix C to the rule provides an operator with further 
guidance on evaluating how each pipeline segment could affect a high 
consequence area.
Leak Detection
    The final rule requires an operator to have some means to detect 
leaks on its pipeline system. The rule further requires an operator to 
evaluate the capability of its leak detection means and modify the 
capability, as necessary, to protect the high consequence area.
    The rule lists factors that an operator must consider when making 
this evaluation. Again, the list is not exclusive. It is simply a 
starting point that an operator must supplement with factors relevant 
to each pipeline segment being evaluated.
    Some examples of leak detection systems include--
    Dynamic flow modeling: This model simulates the operating 
conditions of the pipeline through hydraulic calculations, then 
compares the computed pressures (based on flow rate, temperature, pipe 
profile, and density) against real time data obtained from various 
measuring points along the pipeline. Deviations are compared against 
alarm set points. When the deviations exceed the set points, the system 
alarms. These systems are normally integrated with the pipeline SCADA 
communications technology. Leak location information is not provided.
    Tracer chemical: This approach requires mixing a very small amount 
(ppb to ppm of total volume) of a specific volatile chemical tracer 
with the contents of a pipeline. The chemical tracer is not a component 
of the pipeline contents and does not occur naturally in the soil. 
After the pipeline is inoculated with the tracer chemical, samples of 
the vapor contained in the soil outside the pipeline are collected. The 
soil vapor samples are obtained from probes or other devices installed 
intermittently along the pipeline. The vapor samples are analyzed by a 
gas chromatograph for the specific tracer chemical that was mixed with 
the pipeline contents. Presence of the tracer chemical in the

[[Page 75399]]

sample can only occur through an active release of pipeline product 
mixed with the tracer into the soil. These systems are able to provide 
single or continuous liquid tightness tests and will provide release 
location information.
    Release Detection Cable: Release detection sensing cables are 
designed to alarm after contact with liquid hydrocarbons at any point 
along their length. The presence of hydrocarbons creates a circuit 
between two sensing wires and triggers an alarm. Typically, leak 
detection cable is installed in slotted PVC conduit that is buried in 
the pipe trench along or below the pipeline. These systems provide 
continuous monitoring via electronic control units capable of 
interfacing with SCADA technology and are able to provide leak location 
information.
    Shut-in (static) released detection: This technique consists of a 
pressure test, with the pipeline filled with its normal contents. 
Between shipments, the pipeline is pressured against a closed valve(s). 
This release detection tool allows the operator to analyze the pipeline 
in a static (no flow) mode, without the complications of dynamic 
modeling. With the pipeline blocked, the pressure (compensated for 
temperature fluctuations) in a section should remain constant. The 
pressure is then monitored for any unexplained pressure losses. This 
test does not provide leak location information.
    Pressure point analysis release detection software: Software for 
this system incorporates two independent methods of release detection: 
pressure point analysis and mass balance. Pattern recognition 
algorithms that distinguish normal operating events from leaks are 
used. With an appropriate communications system, this system can 
provide the calculated location of a release.
Emergency flow restricting devices (EFRDs)
    The rule requires an operator to install an EFRD if the operator 
determines that an EFRD is needed on a pipeline segment to protect a 
high consequence area in the event of a hazardous liquid pipeline 
release. The rule lists certain factors that an operator must consider 
in making this determination, to be supplemented with other factors the 
operator determines are relevant to the pipeline segment being 
evaluated. Listed factors an operator must consider include the 
swiftness of leak detection and pipeline shutdown capabilities, the 
type of commodity carried, the rate of potential leakage, the volume 
that can be released, topography or pipeline profile, the potential for 
ignition, proximity to power sources, location of nearest response 
personnel, specific terrain between the pipeline and the high 
consequence area, and benefits expected by reducing the spill size.
    Installing an EFRD on a pipeline segment is only one of several 
possible preventive or mitigative measure that an operator can take to 
provide additional protection to a high consequence area.
What is a Process for Continual Evaluation and Assessment to Maintain a 
Pipeline's Integrity? Section 195.452(j)
    The integrity assessment requirements do not stop with the baseline 
integrity assessment. An operator must continue to assess the integrity 
of the line pipe and evaluate the integrity of each pipeline segment 
that could affect a high consequence area. The rule requires an 
operator to conduct a periodic evaluation of each pipeline segment, as 
frequently as needed, to assure the pipeline's integrity. An operator 
would determine frequency based on specified risk factors plus other 
factors specific to the pipeline segment.
    The evaluation is based, in part, on the information analysis the 
operator has made of the entire pipeline to determine what history and 
operations elsewhere could be relevant to the segment. The evaluation 
must also consider the past and present integrity assessment results, 
and decisions about repair, and preventive and mitigative actions. The 
evaluation must be done by a person qualified to evaluate the results 
and other related data.
    As with the baseline assessment, the continual integrity assessment 
method must be by internal inspection, pressure test, or other 
technology that provides an equivalent understanding of the condition 
of the line pipe. As with the baseline assessment, if an operator 
chooses other technology as a re-assessment method, the operator must 
give 90-days advance notice (by mail or facsimile) to OPS.
    An operator must conduct the integrity re-assessment at intervals 
not to exceed five years, except in those limited instances where the 
operator can clearly justify an extended interval. The rule requires 
that an operator base the continual assessment intervals on the risk 
the line pipe poses to the high consequence area to determine the 
priority for assessing the pipeline segments. An operator must 
establish the assessment intervals using specified risk factors 
(supplemented by risk factors relevant to the pipeline segment), the 
information analysis, and analysis of the results from the last 
integrity assessment.
    The rule recognizes limited exceptions to the five-year period.
     An operator may be able to justify an engineering basis 
for a longer assessment interval on a segment of line pipe. The 
operator must support the justification by a reliable engineering 
evaluation combined with the use of other technology, such as external 
monitoring technologies. An operator would also have to demonstrate 
that the other technology would provide an understanding of the line 
pipe equivalent to that obtained by an assessment conducted at an 
interval of five years or less.
     The other exception is that an operator may not be able to 
conduct an integrity assessment on a segment of pipe within the 
required period because sophisticated internal inspection devices or 
other technology is not available. An operator must justify the reasons 
why it cannot comply with the required assessment period of not more 
than five years and must also demonstrate the actions it is taking to 
evaluate the integrity of the pipeline segment in the interim.
    In either instance, the operator must inform OPS of its proposed 
variance from intervals of not more than five years. A 90-day advance 
notice before the end of intervals of not more than five years is 
needed if the operator will require a longer assessment interval 
because sophisticated technology is not available. If the operator is 
justifying a longer assessment interval on an engineering basis, notice 
must be given nine months before the end of the interval of five years 
or less.
     The engineering-based exception has been included in the 
rule to encourage the use of advanced alternative technologies. It is 
intended for use in those instances where an operator is employing an 
advanced alternative technology and should therefore be dictated by the 
use of such technology. It is intended to be a limited exception to the 
interval of five years or less and not to exceed an additional two 
years whenever possible.
What Methods To Measure Program Effectiveness Must Be Used? Section 
195.452(k)
    The final rule requires that an operator include in its integrity 
management program methods to measure whether the program is effective 
in assessing and evaluating the integrity of each pipeline segment and 
in protecting the high consequence areas. Because performance measures 
must be tailored to an individual

[[Page 75400]]

program, the rule does not specify the measures an operator has to 
include.
    However, in the Appendix C to this rule we have provided guidance 
on performance measures. The guidance also gives examples of categories 
of performance measures that an operator should consider. Examples of 
measures that an operator could adapt for its program include--
     Selected Activity Measures--Measures that monitor the 
surveillance and preventive activities the operator has implemented.
     Deterioration Measures--Operation and Maintenance trends 
that indicate when the integrity of the system is weakening despite 
preventive measures.
     Failure Measures--Leak History, incident response, product 
loss, etc. These measures will indicate progress towards fewer spills 
and less damage.
     Internal vs. External Comparisons. Comparing data that 
could affect a high consequence area with data from pipeline segments 
in other areas of the system, and comparing data external to the 
pipeline segment.
What Records Must Be Kept? Section 195.452(l)
    The final rule requires that an operator maintain certain records 
for inspection, including its written integrity management program. 
This requirement is not any different from the procedural manual an 
operator is required to maintain for operations, maintenance and 
emergencies. An operator would also be required to maintain for review 
during inspection documents that support the decisions and analyses 
made, and actions taken to implement and evaluate each element of the 
integrity management program. This would also include records 
documenting any modifications, justifications, variances, deviations 
and determinations made. Again, this requirement is no different from 
the myriad documents an operator now maintains to comply with the other 
provisions of the pipeline safety regulations.
    The rule cannot possibly list all records that an operator would 
have to maintain to demonstrate its compliance with the integrity 
management program requirements. Appendix C provides examples of some 
documents that an operator would need to maintain for inspection. The 
list is not exhaustive. Listed examples include:
     Record identifying all pipeline segments that could affect 
a high consequence area;
     Baseline assessment plan that includes each required plan 
element;
     Modifications to the baseline assessment plan and reasons 
for the modifications;
     Use of and support for alternative practices;
     An integrity management program framework that includes 
each of the required program elements, updates and modifications to the 
initial framework and eventual program;
     Process for establishing the baseline and continual re-
assessment intervals;
     Process for identifying population changes around a 
pipeline segment;
     Any variance from the required re-assessment intervals, 
and reasons for the deviation;
     Results of the baseline and continual integrity 
assessments;
     Results of the information analyses and periodic 
evaluations;
     Process for integrating and analyzing information about 
the integrity of a pipeline;
     Process and risk factors used for determining the 
frequency of periodic evaluations;
     Schedule for reviewing and analyzing integrity assessment 
results;
     Schedule for evaluating and repairing anomalies found 
during the integrity assessment;
     Any deviation from the required repair schedule for the 
listed conditions;
     Criteria for repair actions; records of anomalies detected 
actions taken to evaluate and repair the anomalies;
     Records of other remedial actions planned or taken;
     Risk analysis to identify additional preventive or 
mitigative measures, records of preventive and mitigative actions 
planned or taken;
     Criteria and process for determining EFRD installation;
     Criteria and process for evaluating leak detection 
capability;
     Program performance measures.

Appendix C

    We are adding a new Appendix C to Part 195. This Appendix gives 
guidance to help an operator implement the requirements of the 
integrity management program rule. An operator is not required to use 
this guidance. The Appendix contains guidance on--
     Information an operator may use to identify a high 
consequence area and factors an operator may use to consider the 
potential impacts of a release on a high consequence area;
     Risk factors an operator may use to determine an integrity 
assessment schedule;
     Safety risk indicator tables for leak history, volume or 
line size, age of pipeline, and product transported, an operator may 
use to determine if a pipeline segment falls into a high, medium or low 
risk category.
     Types of internal inspection tools an operator may use to 
find pipeline anomalies;
     Measures an operator could use to measure an integrity 
management program's performance; and
     Types of records an operator will have to maintain.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Regulatory Policies and Procedures

    The Department of Transportation (DOT) considers this action to be 
a significant regulatory action under section 3(f) of Executive Order 
12866 (58 FR 51735; October 4,1993). Therefore, it was forwarded to the 
Office of Management and Budget. This final rule is significant under 
DOT's regulatory policies and procedures (44 FR 11034: February 26, 
1979).

Consideration of Public Comments

    We received a number of comments that related to the draft 
Regulatory Evaluation that accompanied the proposed rule (65 FR 21695). 
OPS has considered those comments and has made changes in this 
evaluation where appropriate. Provided below is a summary of the 
comments and any changes made to the Regulatory Evaluation.
    1. Costs for Developing Integrity Management Programs. Commenters 
suggested that the costs for developing integrity management programs 
were underestimated. The comments suggested that integrity management 
programs can cost $75-$300 thousand, rather than the $25-$75 thousand 
range used in the draft evaluation. OPS acknowledges that its estimate 
of the costs to prepare integrity management programs may have been too 
low. OPS has used the suggested range in this evaluation. OPS has 
continued to assume that 10 percent of the operators covered by the 
rule (those who own or operate 500 or more miles of hazardous liquid 
pipeline) will have already developed company-specific integrity 
management programs. Operators' costs to develop these programs have 
already been expended; operators will incur no further costs as a 
result of this rule. OPS has revised the estimated cost that will be 
incurred by the remaining 90 percent of covered operators for 
developing programs to $100 thousand. (It is assumed that the programs 
operators develop that comply with the final rule will be less costly 
than the comprehensive programs that some operators have developed 
voluntarily.)

[[Page 75401]]

    2. Costs for Periodic Update and Documentation. Commenters also 
suggested that the costs for periodic program updates and documentation 
(called ``reports'' in the draft evaluation) were underestimated. They 
estimated a range of $50-150 thousand for this work. OPS agrees that 
the estimate in the draft evaluation was unrealistically low. In that 
evaluation, the only documentation considered was records of 
assessments, which were assumed to be produced by lower level personnel 
under general supervision. The draft evaluation failed to consider the 
need to evaluate whether changes to the program are needed, because 
technology or the pipeline changes or because high consequence areas 
are redrawn (as they will be periodically), and to make those changes. 
Operators will expend resources to evaluate these things, even if few 
changes are made. This will add costs. No update or changes will be 
required in some years, when the only expense will be to consider new 
information to ascertain whether an update is needed. OPS cannot 
accept, however, the presumption that the range of such annual costs 
will significantly overlap the range of costs to develop the programs 
in the first place, as suggested by the comment. Significantly less 
work is involved in updating an existing program. For purposes of this 
evaluation, OPS included the need to update an integrity management 
program. Costs for this effort were estimated at $8,000 per year, which 
is considered reasonable compared to the estimated cost for developing 
the program initially. Routine documentation is estimated at $2,000 
annually, an increase of a factor of two from the estimate included in 
the draft evaluation. The net annual cost for updates and documentation 
is thus $10,000 per operator or $660 thousand in total.
    OPS also included in this final evaluation costs for data 
integration. These costs will include a need to realign company-
internal data management systems in the first year and continuing costs 
for the professional review of the integrated data related to the 
integrity of pipelines in high consequence areas. OPS has estimated 
costs for these activities at $50,000 per operator in the first year 
after the rule (when internal data management realignment will occur) 
and $25,000 per year thereafter.
    3. New Assessment will be Required. Commenters disagreed with the 
assumption in the draft evaluation that no additional integrity 
assessment would be required, since operators were conducting internal 
inspection and pressure testing at a rate sufficient to complete all 
required baseline assessment in the first seven years after the 
effective date of the rule. The total number of affected pipeline miles 
has also increased since the proposed rule. Because of these changes, 
OPS agrees that integrity assessment of the number of pipeline miles 
affected by the final rule will require an increase in the rate of 
assessment represented by recent industry practice. OPS continues to 
assume that initial assessment would have proceeded at the current rate 
if there were no rule. OPS has estimated costs for assessment that will 
be required above that rate to assure that all affected pipeline is 
assessed in the seven years following the effective date of the rule.
    4. Need for More Detailed Cost-benefit Analysis. Commenters, 
including the Technical Hazardous Liquid Pipeline Safety Standards 
Committee (Advisory Committee), contended that the Regulatory 
Evaluation is not consistent with the OPS framework for cost-benefit 
analyses or in conformance with applicable standards. They suggested 
that OPS perform a more rigorous evaluation, perhaps in parallel with 
the rulemaking. They recommended that the suggested analysis quantify 
the benefits of the proposed rule, which was not done for the draft 
evaluation. The Advisory Committee unanimously voted that the Cost-
Benefit Analysis was not sufficient. Commenters also cited failure to 
identify a specific target problem.
    OPS has revised the regulatory evaluation to more closely follow 
the form of the framework. This included identifying the target 
problem. OPS agrees with the concerns of the Advisory Committee and 
other commenters but notes that it does not have adequate data on 
pipeline spills to accurately gauge the benefits of this rule. The DOT 
Inspector General, in its audit report, ``Pipeline Safety Program 
Report No. RT-2000-069, March 12, 2000, stated, ``OPS accident database 
contains inaccurate causal information and underestimates property 
damage.'' These problems make it difficult to prepare a more rigorous 
analysis. OPS has done some further research to examine the 
availability of additional data. OPS turned to data from the National 
Oceanographic and Atmospheric Administration (NOAA), the lead Federal 
Agency on quantifying the costs of hazardous liquid spills.
    In their paper, Putting Response and Natural Resource Damage Costs 
in Perspective, Douglas Helton and Tony Penn, employees of NOAA, wrote 
that, ``[t]he total private and social cost of oil spills is of great 
interest to industry, responders, and regulators, but relatively few 
incidents have been examined in detail. Furthermore, publicly available 
cost data are often limited to State and Federal response costs and 
natural resource damages. Significant categories of costs, such as 
private response costs, third party claims, and vessel or facility 
repair costs, are often not publicly available.'' The authors further 
warn that, ``[w]hen cost estimates are reported, they should be 
considered partial and spill volumes should be viewed with some 
skepticism.'' They conclude that, ``[f]ailure to consider these 
additional cost categories because of unavailable data may result in 
erroneous conclusions regarding the total cost of spills and the 
significance of any one category.''
    Helton and Penn studied 48 spills between 1984 and 1997. (Note that 
most were not from pipelines.) Cost categories varied widely. Third 
party claims varied from less than 1% to more than 95% of total 
damages. Natural resource damages also varied from under 3% to 95%. 
Response costs also varied widely. The data set included 5 pipeline oil 
spills. The total known costs of the pipeline spills ranged from $4.3 
million to $71.4 million.
    The report concludes that, ``[s]pills are costly events, and 
depending on the size and location of the spill may cost millions of 
dollars * * * The inability to account for all the costs of spills also 
has implications in other regulatory programs. Costs per unit spilled 
are often used in regulatory settings and the lack of complete data on 
the total costs of spills might result in inadequate liability 
limits.''
    OPS recognizes its data problems. To illustrate a few examples, the 
original estimate of the PEPCO spill the operator provided was $50,000 
+ of property damage. On further prodding the operator responded with 
supplemental reports raising costs to over $50 million. Note that OPS 
reporting of accidents lumps together the categories of product lost, 
property damage and response costs, and environmental damage. This 
makes any kind of analysis extremely difficult.
    A closer examination of OPS spill reports confirmed the DOT 
Inspector General's audit conclusion that OPS data collection 
concerning costs of oil spills is poor. The cause of this problem is 
two-fold.
    (1) The need to collect improved data by requiring operators to 
report their data by category, for example to separately indicate cost 
of product loss, property damage to the operator, private parties, and 
to the public in terms of

[[Page 75402]]

natural resource damages. A more detailed listing of the costs of 
restoration and clean-up is necessary for better analysis, and
    (2) Presently, accident reporting regulations require that 
operators report accident cost no later than 30 days from the incident 
occurrence. Supplemental reports are required thereafter when new 
information is available. Because of the complexity of some major oil 
spills, cleanup and restoration costs may not be known for several 
years after the spill. In a 1997 accident that OPS recently reexamined, 
the final costs have not been decided because the case is still under 
litigation.
    Pipeline operators, as well as OPS, have not been diligent in 
requesting and providing supplemental reports. OPS will soon be taking 
corrective actions to ensure that timely and accurate supplemental 
reports are provided. In the absence of appropriate data OPS recognizes 
that it cannot appropriately determine the benefits of regulations 
which reduce the number of oil spills. However, as the data from NOAA 
indicate as well as the recent information from the PEPCO spill, even 
the reported costs from oil spills represent a significant social cost 
to society. OPS regrets its data problems. However, as NOAA reports, 
OPS is not alone among Federal regulatory agencies in collecting 
insufficient spill data. OPS has recently proposed changes to its gas 
accident reporting. It will be proposing changes to its oil spill 
accident reporting requirements in the future.
    However, the importance of this regulation in preventing the 
consequences of releases from hazardous liquid pipelines that could 
affect high consequence areas requires that OPS place this requirement 
on the industry in the absence of complete spill data. As stated in 
this evaluation, OPS concludes that the rule is justified based on the 
modest costs to implement and the subjective benefits of improving 
knowledge of pipe condition, addressing public concerns, and reducing 
the frequency and consequence of pipeline releases that affect high 
consequence areas. OPS concludes that this is adequate justification.
    5. The definition of high consequence areas should be expanded to 
include all national parks and fish hatcheries. The Department of the 
Interior and the Environmental Protection Agency strongly recommended 
that the National Parks and National Fish Hatcheries be included as 
high consequence areas. We have not included these areas in the 
definition of high consequence areas. We will consider additional 
protection for these areas, among others, in a future rulemaking.
    The following section summarizes the final regulatory evaluation's 
findings.
    Hazardous liquid pipeline spills can adversely affect human health 
and the environment. The magnitude of this impact differs. There are 
some areas in which the impact of a spill will be more significant than 
it would be in others due to concentrations of people who could be 
affected or to the presence of environmental resources that are 
unusually sensitive to damage. Because of the potential for dire 
consequences of pipeline failures in certain areas, these areas merit a 
higher level of protection. OPS is promulgating this regulation to 
afford the necessary additional protection to these high consequence 
areas.
    Numerous investigations by OPS and the National Transportation 
Safety Board (NTSB) have highlighted the importance of protecting the 
public and environmentally sensitive areas from pipeline failures. NTSB 
has made several recommendations to ensure the integrity of pipelines 
near populated and environmentally sensitive areas. These 
recommendations included requiring periodic testing and inspection to 
identify corrosion and other damage, establishing criteria to determine 
appropriate intervals for inspections and tests, determining hazards to 
public safety from electric resistance welded pipe and requiring 
installation of automatic or remotely-operated mainline valves on high-
pressure lines to provide for rapid shutdown of failed pipelines.
    Congress also directed OPS to undertake additional safety measures 
in areas that are densely populated or unusually sensitive to 
environmental damage. These statutory requirements included having OPS 
prescribe standards for identifying pipelines in high density 
population areas, unusually sensitive environmental areas, and 
commercially navigable waters; issue standards requiring periodic 
inspections using internal inspection devices on pipelines in densely-
populated and environmentally sensitive areas; and survey and assess 
the effectiveness of emergency flow restricting devices, and prescribe 
regulations on circumstances where an operator must use the devices.
    This rulemaking addresses the target problem described above, and 
is a comprehensive response to NTSB's recommendations and Congressional 
mandates, as well as pipeline safety and environmental issues raised 
over the years.
    This rule focuses on a systematic approach to integrity management 
to reduce the potential for hazardous liquid pipeline failures that 
could affect populated and unusually sensitive environmental areas, and 
commercially navigable waterways. This rulemaking requires pipeline 
operators to develop and follow an integrity management program that 
continually assesses, through internal inspection, pressure testing, or 
equivalent alternative technology, the integrity of those pipeline 
segments that could affect areas we have defined as high consequence 
areas i.e., populated areas, areas unusually sensitive to environmental 
damage, and commercially navigable waterways. The program must also 
evaluate the segments through comprehensive information analysis, 
remediate integrity problems and provide additional protection through 
preventive and mitigative measures.
    This final rule (the first in a series of integrity management 
program regulations) covers hazardous liquid pipeline operators that 
own or operate 500 or more miles of pipeline used in transportation. 
OPS intends to propose integrity management program requirements for 
the liquid operators not covered by this final rule and for natural gas 
transmission operators. OPS chose to start the series with this group 
of hazardous liquid operators because the pipelines they operate have 
the greatest potential to adversely affect the environment, based on 
the volume of product these pipelines transport. Further, by focusing 
first on these liquid operators, OPS is addressing requirements for an 
estimated 86.7 percent of hazardous liquid pipelines. It is estimated 
that approximately 35.5 thousand miles (of the 157,000 miles of 
hazardous liquid pipeline in the U.S.) will be impacted by this final 
rule.
    We have estimated the cost to develop the necessary program at 
approximately $5.94 million, with an additional annual cost for program 
upkeep and reporting of $660,000. An operator's program begins with a 
baseline assessment plan and a framework that addresses each required 
program element. The framework indicates how decisions will initially 
be made to implement each element. As decisions are made and operators 
evaluate the effectiveness of the program in protecting high 
consequence areas, the program will be continually updated and 
improved.
    The rule requires a baseline assessment of covered pipeline 
segments through internal inspection, pressure test, or use of other 
technology capable of comparable performance. The baseline assessment 
must be completed

[[Page 75403]]

within seven years after the final rule becomes effective. After this 
baseline assessment, an operator is further required to periodically 
re-assess and evaluate the pipeline segment to ensure its integrity. It 
is estimated that the cost of periodic reassessment will generally not 
occur until the sixth year unless the baseline assessment indicates 
significant defects that would require earlier reassessment. 
Integrating information related to the pipeline's integrity is a key 
element of the integrity management program. Costs will be incurred in 
realigning existing data systems to permit integration and in analysis 
of the integrated data by knowledgeable pipeline safety professionals. 
The total costs for the information integration requirements in this 
rule are $2.95 million in the first year and $1.5 million annually 
thereafter.
    The rule requires operators to identify additional preventive or 
mitigative measures that would enhance public safety or environmental 
protection based on a risk analysis of the pipeline segment. One of the 
many preventive or mitigative actions an operator may take is to 
install an EFRD on the pipeline segment. OPS could not estimate the 
total cost of installing EFRDs because OPS does not know how many 
operators will install them. Additionally, requirements have been added 
for an operator to evaluate its leak detection capability and modify 
that capability, if necessary. OPS does not know how many operators 
currently have leak detection systems or how many will be installed or 
upgraded as a result of this rule. OPS was therefore also unable to 
estimate the total costs of the leak detection requirements.
    Affected operators will be required to assess more line pipe in 
segments that could affect high consequence areas as a result of this 
rule than they would have been expected to assess if the rule had not 
been issued. Integrity assessment consists of a baseline assessment, to 
be conducted over the first seven years after the effective date of the 
rule, and subsequent re-assessment at intervals not to exceed every 
five years.
    OPS has estimated the annual cost of additional baseline assessment 
that will be required by this rule as $9.95 million. The cost for 
additional re-assessment that will be required to meet the five-year 
re-assessment requirement is $17 million per year. Cost impact will be 
greater in the sixth and seventh years after the effective date of the 
rule due to an overlap between baseline inspection and the initial 
subsequent testing. The additional costs in these two years are 
estimated at $38.2 million.
    The benefits of this rule can not easily be quantified but can be 
described in qualitative terms. Issuance of this final rule ensures 
that all operators will perform at least to a baseline safety level and 
will contribute to an overall higher level of safety and environmental 
performance nationwide. It will lead to greater uniformity in how risk 
is evaluated and addressed and will provide more clarity in discussion 
by government, industry and the public about safety and environmental 
concerns and how they can be resolved.
    Much of the final rule is written in performance-based language. A 
performance-based approach provides several advantages: encouraging 
development and use of new technologies; supporting operators' 
development of more formal, structured risk evaluation programs and 
OPS's evaluation of the programs; and providing greater ability for 
operators to customize their long-term maintenance programs.
    The rule has also stimulated the pipeline industry to begin 
developing a supplemental consensus standard to support risk-based 
approaches to integrity management. The rule has further fostered 
development of industry-wide technical standards, such as repair 
criteria to use following an internal inspection.
    Our emphasis on an integrity-based approach encourages a balanced 
program, addressing the range of prevention and mitigation needs and 
avoiding reliance on any single tool or overemphasis on any single 
cause of failure. This orientation will lead to addressing the most 
significant risks in populated areas, unusually sensitive environmental 
areas, and commercially navigable waterways. Commercially navigable 
waterways are included because of their importance as a supply route of 
vital resources to many American communities as well as their role in 
the national defense system. This integrity-based approach is the best 
opportunity to improve industry performance and assure that these high 
consequence areas get the protection they need. It also addresses the 
interrelationships among failure causes and benefits the coordination 
of risk control actions, beyond what a solely compliance-based approach 
would achieve.
    The final rule provides for a verification process, which gives the 
regulator a better opportunity to influence the methods of assessment 
and the interpretation of results. OPS will provide a beneficial 
challenge to the adequacy of an operator's decision process. Requiring 
operators to use the integrity management process, and having 
regulators validate the adequacy and implementation of this process, 
should expedite the operators' rates of remedial action, thereby 
strengthening the pipeline system and reducing the public's exposure to 
risk.
    A particularly significant benefit is the quality of information 
that will be gathered as a result of this proposal to aid operators' 
decisions about providing additional protections. Two essential 
elements of the integrity management program are that an operator 
continually assess and evaluate the pipeline's integrity, and perform 
an analysis that integrates all available information about the 
pipeline's integrity. The process of planning, assessment and 
evaluation will provide operators with better data on which to judge a 
pipeline's condition and the location of potential problems that must 
be addressed.
    Integrating this data with the environmental and safety concerns 
associated with high consequence areas will help prompt operators and 
the Federal and state governments to focus time and resources on 
potential risks and consequences that require greater scrutiny and the 
need for more intensive preventive and mitigation measures. If baseline 
and periodic assessment data is not evaluated in the proper context, it 
is of little or no value. It is imperative that the information an 
operator gathers is assessed in a systematic way as part of the 
operator's ongoing examination of all threats to the pipeline 
integrity. The rule is intended to accomplish that.
    The public has expressed concern about the danger hazardous liquid 
pipelines pose to their neighborhoods. The integrity management process 
leads to greater accountability to the public for both the operator and 
the regulator. This accountability is enhanced through our choice of a 
map-based approach to defining the areas most in need of additional 
protection--the visual depiction of the populated areas, unusually 
sensitive environmental areas, and commercially navigable waterways in 
need of protection focuses on the safety and environmental issues in a 
manner that will be easily understandable to everyone. The system 
integrity requirements and the sharing of information about their 
implementation and effectiveness will assure the public that operators 
are continually inspecting and evaluating the threats to pipelines that 
pass through or close to populated areas to better ensure that the 
pipelines are safe.

[[Page 75404]]

    OPS has not provided quantitative benefits for the continual 
integrity management evaluation required in this final rule. OPS does 
not believe, however, that requiring this comprehensive process, 
including the re-assessment of pipelines in high consequence areas at a 
minimum of once every five years, will be an undue burden on hazardous 
liquid operators covered by this proposal. OPS believes the added 
security this assessment will provide and the generally expedited rate 
of strengthening the pipeline system in populated and important 
environmental areas and commercially navigable waterways, is benefit 
enough to promulgate these requirements.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). OPS 
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 hazardous liquid operators that own or operate 500 or 
more miles of pipeline. Because of this limitation on pipeline mileage, 
only 66 hazardous liquid pipeline operators (large national energy 
companies) covering 86.7 percent of regulated liquid transmission lines 
are impacted by this final rule. Based on this, and the evidence 
discussed above, I certify that this final rule will not have a 
significant impact on a substantial number of small entities.

Paperwork Reduction Act

    This rule contains information collection requirements. As required 
by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), the 
Department of Transportation has submitted a copy of the Paperwork 
Reduction Act Analysis to the Office of Management and Budget for its 
review. The name of the information collection is ``Pipeline Integrity 
Management in High Consequence Areas.'' The purpose of this information 
collection is designed to require operators of hazardous liquid 
pipelines to develop a program to provide direct integrity testing and 
evaluation of hazardous liquid pipelines in high consequence areas.
    Several commenters (pipeline operators and trade associations), 
suggested that OPS underestimated the time and cost to develop the 
necessary program as well as the time and costs to revise the program. 
OPS concurs with these comments and has revised the costs burden hours 
as shown below.
    Sixty-six hazardous liquid operators will be subject to this final 
rule. It is estimated that 59 of these operators will have to develop 
integrity management programs taking approximately 2800 hours per 
program. (Ten percent of hazardous liquid operators are estimated to 
already have sufficient programs to comply with the rule.) Each of the 
59 operators would also have to devote 1,000 in the first year to 
integrate this data into current management information systems.
    Additionally, all 66 operators will be required to update their 
programs on a continual basis. This will take approximately 330 hours 
per program annually. An additional 500 hours per operator (for the 90% 
of operators who do not have a program or whose program does not comply 
with the rule) will be required to annually integrate the data into the 
operator's current management information systems.
    Operators are required to either use hydrostatic testing or smart 
pigging as a method to assess their pipelines. However, operators can 
use another technology if it can demonstrate it provides an equivalent 
understanding of the condition of the line pipe as the other two 
assessment methods. Operators have to provide OPS 90-days notice (by 
mail or facsimile) before using the other technology. OPS believes that 
few operators will choose this option. If they do choose an alternate 
technology, notice preparation should take approximately one hour. 
Because OPS believes few if any operators will elect to use other 
technologies, the burden was considered minimal and therefore not 
calculated.
    Additionally, operators could seek a variance in limited situations 
from the required five-year continual re-assessment interval if they 
can provide the necessary justification and supporting documentation. 
Notice would have to be provided to OPS when an operator seeks a 
variance. OPS believes that approximately 10% of operators may request 
a variance. This is approximately 7 operators. The advance notification 
can be in the form of letter or fax. OPS believes the burden of a 
letter or fax is minimal and therefore did not add it to the overall 
burden hours discussed above.
    Organizations and individuals desiring to submit comments on the 
information collection should direct them to the Office of Information 
and Regulatory Affairs, OMB, Room 10235, New Executive Office Building, 
Washington, D.C. 20503: Attention Desk Officer for the Department of 
Transportation. Comments must be sent within 30 days of the publication 
of this final rule.
    The Office of Management and Budget is specifically interested in 
the following issues concerning the information collection:
     Evaluating whether the collection is necessary for the 
proper performance of the functions of the Department, including 
whether the information would have a practical use;
     Evaluating the accuracy of the Department's estimate of 
the burden of the collection of information, including the validity of 
assumptions used;
     Enhancing the quality, usefulness and clarity of the 
information to be collected; and minimizing the burden of collection of 
information on those who are to respond, including through the use of 
appropriate automated electronic, mechanical, or other technological 
collection techniques or other forms of information technology; e.g., 
permitting electronic submission of responses.
    According to the Paperwork Reduction Act of 1995, no persons are 
required to respond to a collection of information unless a valid OMB 
control number is displayed. The valid OMB control number for this 
information collection will be published in the Federal Register after 
it is approved by the OMB. For more details, see the Paperwork 
Reduction Analysis available for copying and review in the public 
docket.

Executive Order 13084

    This final rule has been analyzed in accordance with the principles 
and criteria contained in Executive Order 13084 (``Consultation and 
Coordination with Indian Tribal Governments''). Because this final rule 
does not significantly or uniquely affect the communities of the Indian 
tribal governments and does not impose substantial direct compliance 
costs, the funding and consultation requirements of Executive Order 
13084 do not apply.

Executive Order 13132

    This final rule has been 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.
    Therefore, the consultation and funding requirements of Executive 
Order 13132 (64 FR 43255; August 10,

[[Page 75405]]

1999) do not apply. Nevertheless, in a November 18-19, 1999 public 
meeting, OPS invited National Association of Pipeline Safety 
Representatives (NAPSR), which includes State pipeline safety 
regulators, to participate in a general discussion on pipeline 
integrity. Again in January, and February 2000, OPS held conference 
calls with NAPSR, to receive their input before proposing an integrity 
management rule.

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

    We have analyzed the final rule 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, and have determined that 
this action would not significantly affect the quality of the human 
environment. We updated the Environmental Assessment that supported the 
proposed rule (65 FR 21695) to reflect the provisions of the final 
rule.
    The final Environmental Assessment determined that the combined 
impacts of the initial baseline assessment (pressure testing or 
internal inspection), the subsequent periodic assessments, and 
additional preventive and mitigative measures that may be implemented 
to protect high consequence areas will result in positive environmental 
impacts. The number of incidents and the environmental damage from 
failures in and near high consequence areas are likely to be reduced. 
However, from a national perspective, the impact is not expected to be 
significant for the pipeline operators covered by the final rule. The 
following discussion summarizes the analysis provided in the final 
Environmental Assessment.
    Many operators covered by the final rule already have internal 
inspection and testing programs. These operators typically place a high 
priority on the pipeline's proximity to populated areas, recreation and 
conservation areas, and environmental resources when making decisions 
about where and when to inspect and test pipelines. As a result, 
pipelines that could affect some of the defined high consequence areas 
have already been recently assessed, and a sizeable fraction of 
pipelines in the remaining locations would likely have been assessed in 
the next several years, without the provisions of the rule. The primary 
effect of the rule--accelerating integrity assessment of pipeline 
segments that could affect some high consequence areas--only shifts the 
improved integrity assurance forward for a few years for most high 
consequence areas. Because pipeline failure rates are low, shifting the 
time at which these segments are assessed forward by a few years, has 
only a small effect on the likelihood of pipeline failures in or near 
high consequence areas.
    Neither internal inspection nor pressure testing protect against 
all threats to pipeline integrity. Specifically, they do not prevent 
outside force damage, the most significant contributor to hazardous 
liquid pipeline failures. However, the rule does require operators to 
conduct an integrated analysis and evaluation of all the potential 
threats to pipeline integrity, and to consider additional preventive or 
mitigative risk control measures to provide enhanced protection. If 
there is a vulnerability to a particular failure cause--like third 
party damage--these evaluations should result in additional risk 
controls to address these threats. However, without knowing the 
specific high consequence area locations, the specific risks present at 
these locations, and the existing operator risk controls (including 
those that surpass the current minimum regulatory requirements), it is 
difficult to determine the impact of this requirement.
    A number of liquid operators covered by the rule already perform 
integrity evaluations or formal risk assessments that consider the 
impacts of pipeline system failures on the environment and population 
in proximity to their lines. These evaluations have already led to 
additional risk controls beyond existing requirements to improve 
protection for these locations. Thus, it is expected that additional 
risk controls resulting from the integrated evaluation will be limited 
with most new actions customized to address site-specific integrity 
issues that the operator may not have previously recognized. For many 
high consequence areas, it is probable that operators will determine 
the existing preventive and mitigative activities provide adequate 
protection, and that the small risk reduction benefits of additional 
risk controls are not justified.
    The primary benefits of the final rule will be to establish 
requirements for conducting integrity assessments and periodic 
evaluations of the pipeline segments that could affect high consequence 
areas. In effect, this will establish uniform integrity management 
programs across the pipeline industry and enhance the integrity 
assessment activities many operators are currently implementing. It 
will also require operators who have minimal, or no, integrity 
assessment and evaluation programs to raise their level of performance. 
Thus, the rule is expected to ensure a more consistent, and overall 
higher level of integrity assurance for high consequence areas across 
the industry.
    In accordance with 40 CFR Section 1508.13, based on the updated 
Environmental Assessment, and no receipt of comment or information 
showing otherwise, we have prepared a Finding of No Significant Impact 
(FONSI) for this final rule. The updated Environmental Assessment and 
the Finding of No Significant Impact are available for review in the 
docket.

List of Subjects in 49 CFR Part 195

    Carbon dioxide, High consequence areas, Integrity assurance, 
Petroleum, Pipeline safety, Reporting and recordkeeping requirements.
    In consideration of the foregoing, OPS 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:

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

Subpart F--Operation and Maintenance

    2. New Secs. 195.450 and 195.452 are added under new undesignated 
centerheadings of ``High Consequence Areas'' and ``Pipeline Integrity 
Management'', respectively, to subpart F to read as follows:

High Consequence Areas

195.450  Definitions.

Pipeline Integrity Management

195.452  Pipeline integrity management in high consequence areas.

High Consequence Areas


Sec. 195.450  Definitions.

    The following definitions apply to this section and Sec. 195.452:
    Emergency flow restricting device or EFRD means a check valve or 
remote control valve as follows:
    (1) Check valve means a valve that permits fluid to flow freely in 
one direction and contains a mechanism to

[[Page 75406]]

automatically prevent flow in the other direction.
    (2) Remote control valve or RCV means any valve that is operated 
from a location remote from where the valve is installed. The RCV is 
usually operated by the supervisory control and data acquisition 
(SCADA) system. The linkage between the pipeline control center and the 
RCV may be by fiber optics, microwave, telephone lines, or satellite.
    High consequence area means:
    (1) A commercially navigable waterway, which means a waterway where 
a substantial likelihood of commercial navigation exists;
    (2) A high population area, which means an urbanized area, as 
defined and delineated by the Census Bureau, that contains 50,000 or 
more people and has a population density of at least 1,000 people per 
square mile;
    (3) An other populated area, which means a place, as defined and 
delineated by the Census Bureau, that contains a concentrated 
population, such as an incorporated or unincorporated city, town, 
village, or other designated residential or commercial area;
    (4) An unusually sensitive area, as defined in Sec. 195.6.

Pipeline Integrity Management


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 pipeline subject to this part.
    (b) What must an operator do? (1) No later than March 31, 2002, an 
operator must develop a written integrity management program that 
addresses the risks on each pipeline segment that could affect a high 
consequence area. An operator must include in the program:
    (i) An identification of all pipeline segments that could affect a 
high consequence area. A pipeline segment in a high consequence area is 
presumed to affect that area unless the operator's risk assessment 
effectively demonstrates otherwise. (See Appendix C of this part for 
guidance on identifying pipeline segments.) An operator must complete 
this identification no later than December 31, 2001;
    (ii) A plan for baseline assessment of the line pipe (see paragraph 
(c) of this section);
    (iii) A framework addressing each element of the integrity 
management program, including continual integrity assessment and 
evaluation (see paragraphs (f) and (j) of this section). The framework 
must initially indicate how decisions will be made to implement each 
element.
    (2) An operator must implement and follow the program it develops.
    (3) In carrying out this section, an operator must follow 
recognized industry practices unless the section specifies otherwise or 
the operator demonstrates that an alternative practice is supported by 
a reliable engineering evaluation and provides an equivalent level of 
public safety and environmental protection.
    (c) What must be in the baseline assessment plan? (1) An operator 
must include each of the following elements in its written baseline 
assessment plan:
    (i) The methods selected to assess the integrity of the line pipe. 
For low frequency electric resistance welded pipe or lap welded pipe 
susceptible to longitudinal seam failure, an operator must select 
integrity assessment methods capable of assessing seam integrity and of 
detecting corrosion and deformation anomalies. An operator must assess 
the integrity of the line pipe by:
    (A) Internal inspection tool or tools capable of detecting 
corrosion and deformation anomalies including dents, gouges and 
grooves;
    (B) Pressure test conducted in accordance with subpart E of this 
part; or
    (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 specified in Sec. 195.58 or to the facsimile number specified 
in Sec. 195.56;
    (ii) A schedule for completing the integrity assessment;
    (iii) An explanation of the assessment methods selected and 
evaluation of risk factors considered in establishing the assessment 
schedule.
    (2) An operator must document, prior to implementing any changes to 
the plan, any modification to the plan, and reasons for the 
modification.
    (d) When must the baseline assessment be completed? (1) Time 
period. An operator must establish a baseline assessment schedule to 
determine the priority for assessing the pipeline segments. An operator 
must complete the baseline assessment by March 31, 2008. An operator 
must assess at least 50% of the line pipe subject to the requirements 
of this section, beginning with the highest risk pipe, by September 30, 
2004.
    (2) Prior assessment. To satisfy the requirements of paragraph 
(c)(1)(i) of this section, an operator may use an integrity assessment 
conducted after January 1, 1996, if the integrity assessment method 
meets the requirements of this section. However, if an operator uses 
this prior assessment as its baseline assessment, the operator must re-
assess the line pipe according to the requirements of paragraph (j)(3) 
of this section.
    (3) Newly-identified areas. (i) When information is available from 
the information analysis (see paragraph (g) of this section), or from 
Census Bureau maps, that the population density around a pipeline 
segment has changed so as to fall within the definition in Sec. 195.450 
of a high population area or other populated area, the operator must 
incorporate the area into its baseline assessment plan as a high 
consequence area within one year from the date the area is identified. 
An operator must complete the baseline assessment of any line pipe that 
could affect the newly-identified high consequence area within five 
years from the date the area is identified.
    (ii) An operator must incorporate a new unusually sensitive area 
into its baseline assessment plan within one year from the date the 
area is identified. An operator must complete the baseline assessment 
of any line pipe that could affect the newly-identified high 
consequence area within five years from the date the area is 
identified.
    (e) What are the risk factors for establishing an assessment 
schedule (for both the baseline and continual integrity assessments)? 
(1) An operator must establish an integrity assessment schedule that 
prioritizes pipeline segments for assessment (see paragraphs (d)(1) and 
(j)(3) of this section). An operator must base the assessment schedule 
on all risk factors that reflect the risk conditions on the pipeline 
segment. The factors an operator must consider include, but are not 
limited to:
    (i) Results of the previous integrity assessment, defect type and 
size that the assessment method can detect, and defect growth rate;
    (ii) Pipe size, material, manufacturing information, coating type 
and condition, and seam type;
    (iii) Leak history, repair history and cathodic protection history;
    (iv) Product transported;
    (v) Operating stress level;
    (vi) Existing or projected activities in the area;
    (vii) Local environmental factors that could affect the pipeline 
(e.g., corrosivity of soil, subsidence, climatic);
    (viii) geo-technical hazards; and

[[Page 75407]]

    (ix) Physical support of the segment such as by a cable suspension 
bridge.
    (2) Appendix C of this part provides further guidance on risk 
factors.
    (f) What are the elements of an integrity management program? An 
integrity management program begins with the initial framework. An 
operator must continually change the program to reflect operating 
experience, conclusions drawn from results of the integrity 
assessments, and other maintenance and surveillance data, and 
evaluation of consequences of a failure on the high consequence area. 
An operator must include, at minimum, each of the following elements in 
its written integrity management program:
    (1) A process for identifying which pipeline segments could affect 
a high consequence area;
    (2) A baseline assessment plan meeting the requirements of 
paragraph (c) of this section;
    (3) An analysis that integrates all available information about the 
integrity of the entire pipeline and the consequences of a failure (see 
paragraph (g) of this section);
    (4) Criteria for repair actions to address integrity issues raised 
by the assessment methods and information analysis (see paragraph (h) 
of this section);
    (5) A continual process of assessment and evaluation to maintain a 
pipeline's integrity (see paragraph (j) of this section);
    (6) Identification of preventive and mitigative measures to protect 
the high consequence area (see paragraph (i) of this section);
    (7) Methods to measure the program's effectiveness (see paragraph 
(k) of this section);
    (8) A process for review of integrity assessment results and 
information analysis by a person qualified to evaluate the results and 
information (see paragraph (h)(2) of this section).
    (g) What is an information analysis? In periodically evaluating the 
integrity of each pipeline segment (paragraph (j) of this section), an 
operator must analyze all available information about the integrity of 
the entire pipeline and the consequences of a failure. This information 
includes:
    (1) Information critical to determining the potential for, and 
preventing, damage due to excavation, including current and planned 
damage prevention activities, and development or planned development 
along the pipeline segment;
    (2) Data gathered through the integrity assessment required under 
this section;
    (3) Data gathered in conjunction with other inspections, tests, 
surveillance and patrols required by this Part, including, corrosion 
control monitoring and cathodic protection surveys; and
    (4) Information about how a failure would affect the high 
consequence area, such as location of the water intake.
    (h) What actions must be taken to address integrity issues? (1) 
General requirements. An operator must take prompt action to address 
all pipeline integrity issues raised by the assessment and information 
analysis. An operator must evaluate all anomalies and repair those 
anomalies that could reduce a pipeline's integrity. An operator must 
comply with Sec. 195.422 in making a repair.
    (2) Discovery of a condition. Discovery of a condition occurs when 
an operator has adequate information about the condition to determine 
the need for repair. Depending on circumstances, an operator may have 
adequate information when the operator receives the preliminary 
internal inspection report, gathers and integrates information from 
other inspections or the periodic evaluation, excavates the anomaly, or 
when an operator receives the final internal inspection report. The 
date of discovery can be no later than the date of the integrity 
assessment results or the final report.
    (3) Review of integrity assessment. An operator must include in its 
schedule for evaluation and repair (as required by paragraph (h)(4) of 
this section), a schedule for promptly reviewing and analyzing the 
integrity assessment results. After March 31, 2004, an operator's 
schedule must provide for review of the integrity assessment results 
within 120 days of conducting each assessment. The operator must obtain 
and assess a final report within an additional 90 days.
    (4) Schedule for repairs. An operator must complete repairs 
according to a schedule that prioritizes the conditions for evaluation 
and repair. An operator must base the schedule on the risk factors 
listed in paragraph (e)(1) of this section and any pipeline-specific 
risk factors the operator develops. If an operator cannot meet the 
schedule for any of the conditions addressed in paragraphs (h)(5)(i) 
through (iv) of this section, the operator must justify the reasons why 
the schedule cannot be met 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 until a 
permanent repair is made. An operator must send a notice to the address 
specified in Sec. 195.58 or to the facsimile number specified in 
Sec. 195.56.
    (5) Special requirements for scheduling repairs--(i) Immediate 
repair conditions. An operator's evaluation and repair schedule must 
provide for immediate repair conditions. To maintain safety, an 
operator will need to temporarily reduce operating pressure or shut 
down the pipeline until the operator can complete the repair of these 
conditions. An operator must base the temporary operating pressure 
reduction on remaining wall thickness. An operator must treat the 
following conditions as immediate repair conditions:
    (A) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (B) Predicted burst pressure less than the maximum operating 
pressure at the location of the anomaly. Burst pressure has been 
calculated from the remaining strength of the pipe, using a suitable 
metal loss strength calculation, e.g., 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 available at the addresses listed 
at Sec. 195.3.
    (C) Dents on the top of the pipeline (above 4 and 8 o'clock 
position) with any indicated metal loss.
    (D) Significant anomaly that in the judgment of the person 
evaluating the assessment results requires immediate action.
    (ii) 60-day conditions. Except for conditions listed in paragraph 
(h)(5)(i) of this section, an operator must schedule for evaluation and 
repair all dents, regardless of size, located on the top of the 
pipeline (above 4 and 8 o'clock position) within 60 days of discovery 
of the condition.
    (iii) Six-month conditions. Except for conditions listed in 
paragraph (h)(5)(i) or (ii) of this section, an operator must schedule 
evaluation and repair of the following within six months of discovery 
of the condition:
    (A) Dents with metal loss or dents that affect pipe curvature at a 
girth or seam weld.
    (B) Dents with reported depths greater than 6% of the pipe 
diameter.
    (C) Remaining strength of the pipe results in a safe operating 
pressure that is less than the current established MOP at the location 
of the anomaly using a suitable safe operating pressure calculation 
method (e.g., ASME/ANSI B31G (``Manual for Determining the Remaining 
Strength of Corroded Pipelines'' (1991)) or AGA Pipeline

[[Page 75408]]

Research Committee Project PR-3-805 (``A Modified Criterion for 
Evaluating the Remaining Strength of Corroded Pipe'' (December 1989)). 
These documents are available at the addresses listed at Sec. 195.3.
    (D) Areas of general corrosion with a predicted metal loss of >50% 
of nominal wall.
    (E) Predicted metal loss of >50% of nominal wall at crossings of 
another pipeline.
    (F) Weld anomalies with a predicted metal loss >50% of nominal 
wall.
    (G) Potential crack indications that when excavated are determined 
to be cracks.
    (H) Corrosion of or along seam welds.
    (I) Gouges or grooves greater than 12.5% of nominal wall.
    (iv) Other conditions. An operator must schedule evaluation and 
repair of the following conditions:
    (A) Data that reflect a change since last assessed.
    (B) Data that indicate mechanical damage that is located on the top 
half of the pipe.
    (C) Data that indicate anomalies abrupt in nature.
    (D) Data that indicate anomalies longitudinal in orientation.
    (E) Data that indicate anomalies over a large area.
    (F) Anomalies located in or near casings, crossings of another 
pipeline, and areas with suspect cathodic protection.
    (i) What preventive and mitigative measures must an operator take 
to protect the high consequence area? (1) General requirements. An 
operator must take measures to prevent and mitigate the consequences of 
a pipeline failure that could affect a high consequence area. These 
measures include conducting a risk analysis of the pipeline segment to 
identify additional actions to enhance public safety or environmental 
protection. Such actions may include, but are not limited to, 
implementing damage prevention best practices, better monitoring of 
cathodic protection where corrosion is a concern, establishing shorter 
inspection intervals, installing EFRDs on the pipeline segment, 
modifying the systems that monitor pressure and detect leaks, providing 
additional training to personnel on response procedures, conducting 
drills with local emergency responders and adopting other management 
controls.
    (2) Risk analysis criteria. In identifying the need for additional 
preventive and mitigative measures, an operator must evaluate the 
likelihood of a pipeline release occurring and how a release could 
affect the high consequence area. This determination must consider all 
relevant risk factors, including, but not limited to:
    (i) Terrain surrounding the pipeline segment, including drainage 
systems such as small streams and other smaller waterways that could 
act as a conduit to the high consequence area;
    (ii) Elevation profile;
    (iii) Characteristics of the product transported;
    (iv) Amount of product that could be released;
    (v) Possibility of a spillage in a farm field following the drain 
tile into a waterway;
    (vi) Ditches along side a roadway the pipeline crosses;
    (vii) Physical support of the pipeline segment such as by a cable 
suspension bridge;
    (viii) Exposure of the pipeline to operating pressure exceeding 
established maximum operating pressure.
    (3) Leak detection. An operator must have a means to detect leaks 
on its pipeline system. An operator must evaluate the capability of its 
leak detection means and modify, as necessary, to protect the high 
consequence area. An operator's evaluation must, at least, consider, 
the following factors--length and size of the pipeline, type of product 
carried, the pipeline's proximity to the high consequence area, the 
swiftness of leak detection, location of nearest response personnel, 
leak history, and risk assessment results.
    (4) Emergency Flow Restricting Devices (EFRD). If an operator 
determines that an EFRD is needed on a pipeline segment to protect a 
high consequence area in the event of a hazardous liquid pipeline 
release, an operator must install the EFRD. In making this 
determination, an operator must, at least, consider the following 
factors--the swiftness of leak detection and pipeline shutdown 
capabilities, the type of commodity carried, the rate of potential 
leakage, the volume that can be released, topography or pipeline 
profile, the potential for ignition, proximity to power sources, 
location of nearest response personnel, specific terrain between the 
pipeline segment and the high consequence area, and benefits expected 
by reducing the spill size.
    (j) What is a continual process of evaluation and assessment to 
maintain a pipeline's integrity? (1) General. After completing the 
baseline integrity assessment, an operator must continue to assess the 
line pipe at specified intervals and periodically evaluate the 
integrity of each pipeline segment that could affect a high consequence 
area.
    (2) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure pipeline integrity. An operator must 
base the frequency of evaluation on risk factors specific to its 
pipeline, including the factors specified in paragraph (e) of this 
section. The evaluation must consider the past and present integrity 
assessment results, information analysis (paragraph (g) of this 
section), and decisions about repair, and preventive and mitigative 
actions (paragraphs (h) and (i) of this section).
    (3) Assessment intervals. An operator must establish intervals not 
to exceed five (5) years for continually assessing the line pipe's 
integrity. An operator must base the assessment intervals on the risk 
the line pipe poses to the high consequence area to determine the 
priority for assessing the pipeline segments. An operator must 
establish the assessment intervals based on the factors specified in 
paragraph (e) of this section, the analysis of the results from the 
last integrity assessment, and the information analysis required by 
paragraph (g) of this section.
    (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 is obtainable under paragraph (j)(2) of 
this section. An operator must notify OPS nine months before the end of 
the intervals of five years or less of the reason why the operator 
intends to justify a longer interval. An operator must send a notice to 
the address specified in Sec. 195.58 or to the facsimile number 
specified in Sec. 195.56. The notice must state a proposed alternative 
interval.
    (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 
intervals of five years or less that the operator may require a longer 
assessment interval. An operator must

[[Page 75409]]

send a notice to the address specified in Sec. 195.58 or to the 
facsimile number specified in Sec. 195.56. The Operator may have up to 
an additional 180 days to complete the assessment.
    (5) Assessment methods. An operator must assess the integrity of 
the line pipe by:
    (i) Internal inspection tool or tools capable of detecting 
corrosion and deformation anomalies including dents, gouges and 
grooves;
    (ii) Pressure test conducted in accordance with subpart E of this 
part; or
    (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 60 days before conducting 
the assessment, by sending a notice to the address specified in 
Sec. 195.58 or to the facsimile number specified in Sec. 195.56.
    (6) However, for low frequency electric resistance welded pipe or 
lap welded pipe susceptible to longitudinal seam failure, an operator 
must select integrity assessment methods capable of assessing seam 
integrity and of detecting corrosion and deformation anomalies.
    (k) What methods to measure program effectiveness must be used? An 
operator's program must include methods to measure whether the program 
is effective in assessing and evaluating the integrity of each pipeline 
segment and in protecting the high consequence areas. See Appendix C of 
this part for guidance on methods that can be used to evaluate a 
program's effectiveness.
    (l) What records must be kept? An operator must maintain for review 
during an inspection:
    (i) A written integrity management program in accordance with 
paragraph (b) of this section.
    (ii) Documents to support the decisions and analyses, including any 
modifications, justifications, variances, deviations and determinations 
made, and actions taken, to implement and evaluate each element of the 
integrity management program listed in paragraph (f) of this section.
    (2) See Appendix C of this part for examples of records an operator 
would be required to keep.

    3. A new Appendix C is added to part 195 to read as follows:

Appendix C to Part 195--Guidance for Implementation of Integrity 
Management Program

    This Appendix gives guidance to help an operator implement the 
requirements of the integrity management program rule in 
Secs. 195.450 and 195.452. Guidance is provided on:
    (1) Information an operator may use to identify a high 
consequence area and factors an operator can use to consider the 
potential impacts of a release on an area;
    (2) Risk factors an operator can use to determine an integrity 
assessment schedule;
    (3) Safety risk indicator tables for leak history, volume or 
line size, age of pipeline, and product transported, an operator may 
use to determine if a pipeline segment falls into a high, medium or 
low risk category;
    (4) Types of internal inspection tools an operator could use to 
find pipeline anomalies;
    (5) Measures an operator could use to measure an integrity 
management program's performance; and
    (6) Types of records an operator will have to maintain.
    I. Identifying a high consequence area and factors for 
considering a pipeline segment's potential impact on a high 
consequence area.
    A. The rule defines a High Consequence Area as a high population 
area, an other populated area, an unusually sensitive area, or a 
commercially navigable waterway. The Office of Pipeline Safety (OPS) 
will map these areas on the National Pipeline Mapping System (NPMS). 
An operator, member of the public, or other government agency may 
view and download the data from the NPMS home page http://www.npms.rspa.dot.gov. OPS will maintain the NPMS and update it 
periodically. However, it is an operator's responsibility to ensure 
that it has identified all high consequence areas that could be 
affected by a pipeline segment. An operator is also responsible for 
periodically evaluating its pipeline segments to look for population 
or environmental changes that may have occurred around the pipeline 
and to keep its program current with this information. (Refer to 
Sec. 195.452(d)(3).) For more information to help in identifying 
high consequence areas, an operator may refer to:
    (1) Digital Data on populated areas available on U.S. Census 
Bureau maps.
    (2) Geographic Database on the commercial navigable waterways 
available on http://www.bts.gov/gis/ntatlas/networks.html.
    (3) The Bureau of Transportation Statistics database that 
includes commercially navigable waterways and non-commercially 
navigable waterways. The database can be downloaded from the BTS 
website at http://www.bts.gov/gis/ntatlas/networks.html.
    B. The rule requires an operator to include a process in its 
program for identifying which pipeline segments could affect a high 
consequence area and to take measures to prevent and mitigate the 
consequences of a pipeline failure that could affect a high 
consequence area. (See Secs. 195.452 (f) and (i).) Thus, an operator 
will need to consider how each pipeline segment could affect a high 
consequence area. The primary source for the listed risk factors is 
a US DOT study on instrumented Internal Inspection devices (November 
1992). Other sources include the National Transportation Safety 
Board, the Environmental Protection Agency and the Technical 
Hazardous Liquid Pipeline Safety Standards Committee. The following 
list provides guidance to an operator on both the mandatory and 
additional factors:
    (1) Terrain surrounding the pipeline. An operator should 
consider the contour of the land profile and if it could allow the 
liquid from a release to enter a high consequence area. An operator 
can get this information from topographical maps such as U.S. 
Geological Survey quadrangle maps.
    (2) Drainage systems such as small streams and other smaller 
waterways that could serve as a conduit to a high consequence area.
    (3) Crossing of farm tile fields. An operator should consider 
the possibility of a spillage in the field following the drain tile 
into a waterway.
    (4) Crossing of roadways with ditches along the side. The 
ditches could carry a spillage to a waterway.
    (5) The nature and characteristics of the product the pipeline 
is transporting (refined products, crude oils, highly volatile 
liquids, etc.) Highly volatile liquids becomes gaseous when exposed 
to the atmosphere. A spillage could create a vapor cloud that could 
settle into the lower elevation of the ground profile.
    (6) Physical support of the pipeline segment such as by a cable 
suspension bridge. An operator should look for stress indicators on 
the pipeline (strained supports, inadequate support at towers), 
atmospheric corrosion, vandalism, and other obvious signs of 
improper maintenance.
    (7) Operating condition of pipeline (pressure, flow rate, etc.) 
Exposure of the pipeline to operating pressure exceeding established 
maximum operating pressure.
    (8) The hydraulic gradient of pipeline.
    (9) The diameter of pipeline, the potential release volume, and 
the distance between the isolation points.
    (10) Potential physical pathways between the pipeline and the 
high consequence area.
    (11) Response capability (time to respond, nature of response).
    (12) Potential natural forces inherent in the area (flood zones, 
earthquakes, subsidence areas, etc.)
    II. Risk factors for establishing frequency of assessment.
    A. By assigning weights or values to the risk factors, and using 
the risk indicator tables, an operator can determine the priority 
for assessing pipeline segments, beginning with those segments that 
are of highest risk, that have not previously been assessed. This 
list provides some guidance on some of the risk factors to consider 
(see Sec. 195.452(e)). An operator should also develop factors 
specific to each pipeline segment it is assessing, including:
    (1) Populated areas, unusually sensitive environmental areas, 
National Fish Hatcheries, commercially navigable waters, areas where 
people congregate.
    (2) Results from previous testing/inspection. (See 
Sec. 195.452(h).)
    (3) Leak History. (See leak history risk table.)
    (4) Known corrosion or condition of pipeline. (See 
Sec. 195.452(g).)
    (5) Cathodic protection history.
    (6) Type and quality of pipe coating (disbonded coating results 
in corrosion).
    (7) Age of pipe (older pipe shows more corrosion--may be 
uncoated or have an ineffective coating) and type of pipe seam. (See 
Age of Pipe risk table.)
    (8) Product transported (highly volatile, highly flammable and 
toxic liquids present a

[[Page 75410]]

greater threat for both people and the environment) (see Product 
transported risk table.)
    (9) Pipe wall thickness (thicker walls give a better safety 
margin)
    (10) Size of pipe (higher volume release if the pipe ruptures).
    (11) Location related to potential ground movement (e.g., 
seismic faults, rock quarries, and coal mines); climatic (permafrost 
causes settlement--Alaska); geologic (landslides or subsidence).
    (12) Security of throughput (effects on customers if there is 
failure requiring shutdown).
    (13) Time since the last internal inspection/pressure testing.
    (14) With respect to previously discovered defects/anomalies, 
the type, growth rate, and size.
    (15) Operating stress levels in the pipeline.
    (16) Location of the pipeline segment as it relates to the 
ability of the operator to detect and respond to a leak. (e.g., 
pipelines deep underground, or in locations that make leak detection 
difficult without specific sectional monitoring and/or significantly 
impede access for spill response or any other purpose).
    (17) Physical support of the segment such as by a cable 
suspension bridge.
    (18) Non-standard or other than recognized industry practice on 
pipeline installation (e.g., horizontal directional drilling).
    B. Example: This example illustrates a hypothetical model used 
to establish an integrity assessment schedule for a hypothetical 
pipeline segment. After we determine the risk factors applicable to 
the pipeline segment, we then assign values or numbers to each 
factor, such as, high (5), moderate (3), or low (1). We can 
determine an overall risk classification (A, B, C) for the segment 
using the risk tables and a sliding scale (values 5 to 1) for risk 
factors for which tables are not provided. We would classify a 
segment as C if it fell above \2/3\ of maximum value (highest 
overall risk value for any one segment when compared with other 
segments of a pipeline), a segment as B if it fell between \1/3\ to 
\2/3\ of maximum value, and the remaining segments as A.
    i. For the baseline assessment schedule, we would plan to assess 
50% of all pipeline segments covered by the rule, beginning with the 
highest risk segments, within the first 3\1/2\ years and the 
remaining segments within the seven-year period. For the continuing 
integrity assessments, we would plan to assess the C segments within 
the first two (2) years of the schedule, the segments classified as 
moderate risk no later than year three or four and the remaining 
lowest risk segments no later than year five (5).
    ii. For our hypothetical pipeline segment, we have chosen the 
following risk factors and obtained risk factor values from the 
appropriate table. The values assigned to the risk factors are for 
illustration only.

Age of pipeline: assume 30 years old (refer to ``Age of Pipeline'' 
risk table)--
Risk Value=5
Pressure tested: tested once during construction--
Risk Value=5
Coated: (yes/no)--yes
Coating Condition: Recent excavation of suspected areas showed 
holidays in coating (potential corrosion risk)--
Risk Value=5
Cathodically Protected: (yes/no)--yes--Risk Value=1
Date cathodic protection installed: five years after pipeline was 
constructed (Cathodic protection installed within one year of the 
pipeline's construction is generally considered low risk.)--Risk 
Value=3
Close interval survey: (yes/no)--no--Risk Value =5
Internal Inspection tool used: (yes/no)--yes. Date of pig run? In 
last five years--Risk Value=1
Anomalies found: (yes/no)--yes, but do not pose an immediate safety 
risk or environmental hazard--Risk Value=3
Leak History: yes, one spill in last 10 years. (refer to ``Leak 
History'' risk table)--Risk Value=2
Product transported: Diesel fuel. Product low risk. (refer to 
``Product'' risk table)--Risk Value=1
Pipe size: 16 inches. Size presents moderate risk (refer to ``Line 
Size'' risk table)--Risk Value=3
    iii. Overall risk value for this hypothetical segment of pipe is 
34. Assume we have two other pipeline segments for which we conduct 
similar risk rankings. The second pipeline segment has an overall 
risk value of 20, and the third segment, 11. For the baseline 
assessment we would establish a schedule where we assess the first 
segment (highest risk segment) within two years, the second segment 
within five years and the third segment within seven years. 
Similarly, for the continuing integrity assessment, we could 
establish an assessment schedule where we assess the highest risk 
segment no later than the second year, the second segment no later 
than the third year, and the third segment no later than the fifth 
year.
    III. Safety risk indicator tables for leak history, volume or 
line size, age of pipeline, and product transported.

                              Leak History
------------------------------------------------------------------------
                                           Leak history  (Time-dependent
         Safety risk  indicator                    defects) \1\
------------------------------------------------------------------------
High....................................  > 3 Spills in last 10 years
Low.....................................   3 Spills in last 10 years
------------------------------------------------------------------------
\1\ Time-dependent defects are those that result in spills due to
  corrosion, gouges, or problems developed during manufacture,
  construction or operation, etc.


                     Line size or Volume transported
------------------------------------------------------------------------
         Safety risk  indicator                      Line size
------------------------------------------------------------------------
High....................................   18"
Moderate................................  10"--16" nominal diameters
Low.....................................   8" nominal
                                           diameter
------------------------------------------------------------------------


                             Age of Pipeline
------------------------------------------------------------------------
                                              Age Pipeline condition
         Safety risk  indicator                   dependent) \1\
------------------------------------------------------------------------
High....................................  > 25 years
Low.....................................   25 years
------------------------------------------------------------------------
\1\ Depends on pipeline's coating & corrosion condition, and steel
  quality, toughness, welding.


                                               Product Transported
----------------------------------------------------------------------------------------------------------------
   Safety risk  indicator                Considerations \1\                         Product examples
----------------------------------------------------------------------------------------------------------------
High........................  (Highly volatile and flammable).........  (Propane, butane, Natural Gas Liquid
                                                                         (NGL), ammonia).
                              Highly toxic............................  (Benzene, high Hydrogen Sulfide content
                                                                         crude oils).
Medium......................  Flammable--flashpoint 100F..............  (Gasoline, JP4, low flashpoint crude
                                                                         oils).
Low.........................  Non-flammable--flashpoint 100+F.........  (Diesel, fuel oil, kerosene, JP5, most
                                                                         crude oils).
----------------------------------------------------------------------------------------------------------------
\1\ The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility,
  flammability, and water solubility determine the Product Indicator. Comprehensive Environmental Response,
  Compensation and Liability Act Reportable Quantity values may be used as an indication of chronic toxicity.
  National Fire Protection Association health factors may be used for rating acute hazards.

    IV. Types of internal inspection tools to use.
    An operator should consider at least two types of internal 
inspection tools for the integrity assessment from the following 
list. The type of tool or tools an operator selects will depend on 
the results from previous internal inspection runs, information 
analysis and risk factors specific to the pipeline segment:
    (1) Geometry Internal inspection tools for detecting changes to 
ovality, e.g., bends, dents, buckles or wrinkles, due to 
construction flaws or soil movement, or other outside force damage;
    (2) Metal Loss Tools (Ultrasonic and Magnetic Flux Leakage) for 
determining pipe wall anomalies, e.g., wall loss due to corrosion.

[[Page 75411]]

    (3) Crack Detection Tools for detecting cracks and crack-like 
features, e.g., stress corrosion cracking (SCC), fatigue cracks, 
narrow axial corrosion, toe cracks, hook cracks, etc.
    V. Methods to measure performance.
    A. General. (1) This guidance is to help an operator establish 
measures to evaluate the effectiveness of its integrity management 
program. The performance measures required will depend on the 
details of each integrity management program and will be based on an 
understanding and analysis of the failure mechanisms or threats to 
integrity of each pipeline segment.
    (2) An operator should select a set of measurements to judge how 
well its program is performing. An operator's objectives for its 
program are to ensure public safety, prevent or minimize leaks and 
spills and prevent property and environmental damage. A typical 
integrity management program will be an ongoing program and it may 
contain many elements. Therefore, several performance measure are 
likely to be needed to measure the effectiveness of an ongoing 
program.
    B. Performance measures. These measures show how a program to 
control risk on pipeline segments that could affect a high 
consequence area is progressing under the integrity management 
requirements. Performance measures generally fall into three 
categories:
    (1) Selected Activity Measures--Measures that monitor the 
surveillance and preventive activities the operator has implemented. 
These measure indicate how well an operator is implementing the 
various elements of its integrity management program.
    (2) Deterioration Measures--Operation and maintenance trends 
that indicate when the integrity of the system is weakening despite 
preventive measures. This category of performance measure may 
indicate that the system condition is deteriorating despite well 
executed preventive activities.
    (3) Failure Measures--Leak History, incident response, product 
loss, etc. These measures will indicate progress towards fewer 
spills and less damage.
    C. Internal vs. External Comparisons. These comparisons show how 
a pipeline segment that could affect a high consequence area is 
progressing in comparison to the operator's other pipeline segments 
that are not covered by the integrity management requirements and 
how that pipeline segment compares to other operators' pipeline 
segments.
    (1) Internal--Comparing data from the pipeline segment that 
could affect the high consequence area with data from pipeline 
segments in other areas of the system may indicate the effects from 
the attention given to the high consequence area.
    (2) External--Comparing data external to the pipeline segment 
(e.g., OPS incident data) may provide measures on the frequency and 
size of leaks in relation to other companies.
    D. Examples. Some examples of performance measures an operator 
could use include--
    (1) A performance measurement goal to reduce the total volume 
from unintended releases by -% (percent to be determined by 
operator) with an ultimate goal of zero.
    (2) A performance measurement goal to reduce the total number of 
unintended releases (based on a threshold of 5 gallons) by ____-% 
(percent to be determined by operator) with an ultimate goal of 
zero.
    (3) A performance measurement goal to document the percentage of 
integrity management activities completed during the calendar year.
    (4) A performance measurement goal to track and evaluate the 
effectiveness of the operator's community outreach activities.
    (5) A narrative description of pipeline system integrity, 
including a summary of performance improvements, both qualitative 
and quantitative, to an operator's integrity management program 
prepared periodically.
    (6) A performance measure based on internal audits of the 
operator's pipeline system per 49 CFR Part 195.
    (7) A performance measure based on external audits of the 
operator's pipeline system per 49 CFR Part 195.
    (8) A performance measure based on operational events (for 
example: relief occurrences, unplanned valve closure, SCADA outages, 
etc.) that have the potential to adversely affect pipeline 
integrity.
    (9) A performance measure to demonstrate that the operator's 
integrity management program reduces risk over time with a focus on 
high risk items.
    (10) A performance measure to demonstrate that the operator's 
integrity management program for pipeline stations and terminals 
reduces risk over time with a focus on high risk items.
    VI. Examples of types of records an operator must maintain.
    The rule requires an operator to maintain certain records. (See 
Sec. 195.452(l)). This section provides examples of some records 
that an operator would have to maintain for inspection to comply 
with the requirement. This is not an exhaustive list.
    (1) a process for identifying which pipelines could affect a 
high consequence area and a document identifying all pipeline 
segments that could affect a high consequence area;
    (2) a plan for baseline assessment of the line pipe that 
includes each required plan element;
    (3) modifications to the baseline plan and reasons for the 
modification;
    (4) use of and support for an alternative practice;
    (5) a framework addressing each required element of the 
integrity management program, updates and changes to the initial 
framework and eventual program;
    (6) a process for identifying a new high consequence area and 
incorporating it into the baseline plan, particularly, a process for 
identifying population changes around a pipeline segment;
    (7) an explanation of methods selected to assess the integrity 
of line pipe;
    (8) a process for review of integrity assessment results and 
data analysis by a person qualified to evaluate the results and 
data;
    (9) the process and risk factors for determining the baseline 
assessment interval;
    (10) results of the baseline integrity assessment;
    (11) the process used for continual evaluation, and risk factors 
used for determining the frequency of evaluation;
    (12) process for integrating and analyzing information about the 
integrity of a pipeline, information and data used for the 
information analysis;
    (13) results of the information analyses and periodic 
evaluations;
    (14) the process and risk factors for establishing continual re-
assessment intervals;
    (15) justification to support any variance from the required re-
assessment intervals;
    (16) integrity assessment results and anomalies found, process 
for evaluating and repairing anomalies, criteria for repair actions 
and actions taken to evaluate and repair the anomalies;
    (17) other remedial actions planned or taken;
    (18) schedule for reviewing and analyzing integrity assessment 
results;
    (19) schedule for evaluation and repair of anomalies, 
justification to support deviation from required repair times;
    (20) risk analysis used to identify additional preventive or 
mitigative measures, records of preventive and mitigative actions 
planned or taken;
    (21) criteria for determining EFRD installation;
    (22) criteria for evaluating and modifying leak detection 
capability;
    (23) methods used to measure the program's effectiveness.

    Issued in Washington DC on November 14, 2000.
Kelley S. Coyner,
Administrator.
[FR Doc. 00-29570 Filed 11-30-00; 8:45 am]
BILLING CODE 4910-60-P