[Federal Register Volume 68, Number 240 (Monday, December 15, 2003)]
[Rules and Regulations]
[Pages 69778-69837]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-30280]



[[Page 69777]]

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

Part II





Department of Transportation





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



Research and Special Programs Administration



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



49 CFR Part 192



Pipeline Safety: Pipeline Integrity Management in High Consequence 
Areas (Gas Transmission Pipelines); Final Rule

  Federal Register / Vol. 68, No. 240 / Monday, December 15, 2003 / 
Rules and Regulations  

[[Page 69778]]


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

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket No. RSPA-00-7666; Amendment 192-95]
RIN 2137-AD54


Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Gas Transmission Pipelines)

AGENCY: Office of Pipeline Safety (OPS), Research and Special Programs 
Administration (RSPA), DOT.

ACTION: Final rule.

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

SUMMARY: This final rule requires operators to develop integrity 
management programs for gas transmission pipelines located where a leak 
or rupture could do the most harm, i.e., could impact high consequence 
areas (HCAs). The rule requires gas transmission pipeline operators to 
perform ongoing assessments of pipeline integrity, to improve data 
collection, integration, and analysis, to repair and remediate the 
pipeline as necessary, and to implement preventive and mitigative 
actions. RSPA/OPS has also modified the definition of HCAs in response 
to a petition for reconsideration from industry associations. This 
final rule comprehensively addresses statutory mandates, safety 
recommendations, and conclusions from accident analyses, all of which 
indicate that coordinated risk control measures are needed to improve 
pipeline safety.

DATES: This final rule takes effect January 14, 2004. The incorporation 
by reference of certain publications in this rule is approved by the 
Director of the Federal Register as of January 14, 2004.
    Privacy Act Information: You may review DOT's complete Privacy Act 
Statement in the Federal Register published on April 11, 2000 (Volume 
65, Number 70; Pages 19477-78) or you may visit the Dockets Management 
System (DMS) Web site at http://dms.dot.gov. You may search the 
electronic form of all comments received into any of our dockets by the 
name of the individual submitting the comment (or signing the comment, 
if submitted on behalf of an association, business, labor union, etc.).
    General Information: You may contact the Dockets Facility by phone 
at (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/search. Once you access this address, type in the 
last four digits of the docket number shown at the beginning of this 
notice (7666), and click on search. You will then be able to read and 
download comments and other documents related to this final rule.

FOR FURTHER INFORMATION CONTACT: Mike Israni by phone at (202) 366-
4571, by fax at (202) 366-4566, or by e-mail at 
[email protected], regarding the subject matter of this final 
rule. General information about the RSPA/OPS programs may be obtained 
by accessing RSPA's Internet page at http://RSPA.dot.gov.

SUPPLEMENTARY INFORMATION: RSPA/OPS believes it can ensure the 
integrity of gas transmission pipelines by requiring each operator to: 
(a) Develop and implement a comprehensive integrity management program 
for pipeline segments where a failure would have the greatest impact on 
the public or property; (b) identify and characterize applicable 
threats to pipeline segments that could impact a high consequence area; 
(c) conduct a baseline assessment and periodic reassessments of these 
pipeline segments; (d) mitigate significant defects discovered from the 
assessment; and (e) continually monitor the effectiveness of its 
integrity program and modify the program as needed to improve its 
effectiveness. This final rule does not apply to gas gathering or to 
gas distribution pipelines.
    This final rule satisfies Congressional mandates that require RSPA/
OPS to prescribe standards that establish criteria for identifying each 
gas pipeline facility located in a high-density population area and to 
prescribe standards requiring the periodic inspection of pipelines 
located in these areas, including the circumstances under which an 
inspection can be conducted using an instrumented internal inspection 
device (smart pig) or an equally effective alternative inspection 
method. The final rule also incorporates the required elements for gas 
integrity management programs mandated in the Pipeline Safety 
Improvement Act of 2002, which was signed into law on December 17, 
2002, and codified at 49 U.S.C. 60109.

Background

Notice of Proposed Rulemaking

    On January 28, 2003, RSPA/OPS published a Notice of Proposed 
Rulemaking (68 FR 4278) that proposed pipeline integrity management 
requirements for gas transmission pipelines. In the preamble to that 
Notice, RSPA/OPS explained in great detail the history of the proposed 
rule and how the proposal addressed statutory mandates, National 
Transportation Safety Board (NTSB) recommendations, and safety 
conclusions drawn from accident analyses. RSPA/OPS had finalized the 
definition of HCAs for gas transmission pipelines in a prior rulemaking 
on August 6, 2002 (67 FR 50824).
    The American Gas Association (AGA), the American Public Gas 
Association (APGA), the Interstate Natural Gas Association of America 
(INGAA), and the New York Gas Group (NYGAS) filed a petition for 
reconsideration of the HCA final rule. Issues raised in the petition 
are discussed in the section titled, Petition for Reconsideration of 
the final rule on the definition of High Consequence Areas. RSPA/OPS 
addressed certain aspects of the petition in the published notice of 
proposed rulemaking on gas transmission pipeline integrity management 
program requirements (68 FR 4278; January 28, 2003). The remaining 
issues were addressed in two notices published on July 17, 2003--
Response to Petition for Reconsideration (68 FR 42456) and Issuance of 
Advisory Bulletin (68 FR 42458).

Pipeline Safety Improvement Act of 2002

    On November 15, 2002, Congress passed the Pipeline Safety 
Improvement Act of 2002, which was signed into law on December 17, 
2002, and codified at 49 U.S.C. 60109. This law requires RSPA/OPS to 
``issue regulations prescribing standards to direct an operator's 
conduct of a risk analysis and adoption and implementation of an 
integrity management program'' no later than 12 months after December 
17, 2002. The statute sets forth minimum requirements for integrity 
management programs for gas pipelines located in HCAs. These 
requirements have been incorporated into this final rule. Statutory 
requirements for an integrity program include conducting baseline and 
reassessment testing of each covered transmission pipeline segment at 
specified intervals, conducting an integrated data analysis on a 
continuing basis, taking actions to address integrity concerns, 
addressing issues raised by RSPA/OPS and by state and local authorities 
under an interstate agent agreement, conducting testing in an 
environmentally appropriate manner, providing notification of changes 
to a program, and permitting a State interstate agent access to the 
risk analysis and integrity management program.

[[Page 69779]]

Petition for Reconsideration of the Final Rule on the Definition of 
High Consequence Areas

    RSPA/OPS issued a final rule defining HCAs for gas transmission 
pipelines on August 6, 2002 (67 FR 50824). On September 5, 2002, the 
American Gas Association (AGA), the American Public Gas Association 
(APGA), the Interstate Natural Gas Association of America (INGAA), and 
the New York Gas Group (NYGAS) filed a petition for the reconsideration 
of the final rule defining HCAs for gas transmission pipelines. This 
petition is in the docket. The petition raised the following issues:
    (1) The splitting of the gas integrity rule into two rulemakings--
the definition and the integrity requirements--causes confusion, 
particularly, since the Potential Impact Zone concept was not included 
in the definition.
    (2) The high consequence area definition should clarify that it 
applies to gas transmission pipelines that have the potential to impact 
high population density areas and does not apply to distribution 
pipelines.
    (3) The ``identified site'' component of the definition (buildings 
and outside areas) is overly broad. The definition should instead use 
the current language in Sec.  192.5 for Class 3 outside areas.
    When this petition was received, RSPA/OPS was in the final stages 
of developing the NPRM on pipeline integrity management for gas 
transmission pipelines in HCAs. In addition to the proposed substantive 
requirements, the NPRM proposed an expanded definition of HCAs and 
proposed to include a definition of a Potential Impact Zone, the area 
likely to be affected by a failure. In the NPRM, RSPA/OPS discussed the 
issues raised in the petition for reconsideration and its belief that 
the proposal, and the final rule to follow, would address the more 
significant of the issues (68 FR 4278, 4295-4296; January 28, 2003). 
RSPA/OPS requested comments on several aspects of the final definition, 
particularly with respect to the ``identified sites'' component. In two 
notices published on July 17, 2003--Response to Petition for 
Reconsideration (68 FR 42458) and Issuance of Advisory Bulletin (68 FR 
42456)--RSPA/OPS addressed the remainder of issues raised by the 
petitioners, and provided guidance to operators of gas transmission 
pipelines on how to identify HCAs.
    Comments received in response to the NPRM on integrity management 
programs, comments at the public meetings following issuance of the 
NPRM, and advice from the Technical Pipeline Safety Standards Committee 
(TPSSC or Committee), the statutory gas pipeline advisory committee, 
indicated the need for greater clarification of how operators are to 
implement the ``identified sites'' aspect of the HCA definition. The 
advisory bulletin published on July 17, 2003 (68 FR 42456) provides 
guidance to gas transmission operators on the steps RSPA/OPS expects 
them to take to determine ``identified sites'' along their pipelines. 
``Identified sites'' include buildings housing people who are confined 
and of limited mobility who would be difficult to evacuate, and outside 
areas and buildings where people gather. The guidance allows operators 
to identify these sites for purposes of planning integrity management 
programs. RSPA has agreed that the intent of the regulation will be 
satisfied if an operator follows the guidance. The guidance has been 
incorporated into this final rule.

Public Meetings Following the NPRM

    On January 28, 2003 (68 FR 4278), RSPA/OPS proposed integrity 
management program requirements for gas transmission pipelines in HCAs. 
The comment period for this proposal was scheduled to close on March 
31, 2003, but RSPA/OPS extended this comment period to April 30, 2003. 
Because the proposal was complex, a series of public meetings were held 
to educate the industry and public about the proposed requirements and 
to listen to comments and concerns.
    On February 20-21, 2003, RSPA/OPS participated in a public workshop 
sponsored by the INGAA and AGA in Houston, and on February 26, 2003, in 
an audio conference jointly sponsored by AGA, APGA, and other pipeline 
trade associations, to give an overview of the proposed rule and 
clarify certain proposed requirements. On March 19, 2003, RSPA/OPS held 
a public meeting in Washington, DC, to address issues raised at the 
INGAA/AGA workshop and to better explain the proposed rule. 
Participants included representatives from the National Association of 
Pipeline Safety Representatives (NAPSR), INGAA, AGA, APGA, and other 
Federal government agencies. Summaries of these meetings are in the 
docket.
    On March 25, 2003, RSPA/OPS briefed the TPSSC members about issues 
raised in the public meetings and heard additional briefings on 
integrity management issues, including the HCA definition. On May 28-
29, 2003, the TPSSC met to vote on the proposed gas integrity 
management rule and the recommend changes.
    On April 25, 2003, RSPA/OPS held another public meeting to discuss 
possible courses of action on issues that had been raised during the 
previous meetings. Participants included State pipeline safety 
representatives, industry representatives, and the general public.
    The comments at the public meetings closely tracked the comments 
received to the docket and the discussions by the TPSSC at its May 2003 
meeting. These issues and the advisory committee's recommendations are 
discussed in the section titled, Gas Advisory Committee Considerations. 
The 12 issues addressed in the comments to the docket are discussed 
below in Comments to NPRM.

Gas Advisory Committee Considerations

    The Technical Pipeline Safety Standards Committee is the Federal 
advisory committee charged with responsibility for advising on the 
technical feasibility, reasonableness, cost-effectiveness, and 
practicability of proposed gas pipeline safety standards. The 15-member 
Committee is comprised of individuals from industry, government, and 
the general public.
    On May 28-30, 2003, the TPSSC met to review the proposed gas 
pipeline integrity management rule and the associated cost-benefit 
analysis. The Committee voted unanimously to accept the proposed 
integrity management rule as technically reasonable, feasible, and 
practicable, subject to the recommended changes identified during 
committee discussion. The Committee decided that before it could vote 
to accept the cost-benefit analysis, RSPA/OPS must revise it in 
compliance with the recommendations at the May 28-30 meeting. RSPA/OPS 
sent a revised cost-benefit analysis to the committee. On July 31, 
2003, the Committee voted to accept the revised cost-benefit analysis. 
The transcripts from both meetings are in the docket.
Discussion on the HCA Definition and Proposed Rule
    The TPSSC made the following recommendations during the May 28-30 
meeting with respect to the HCA definition and the language in the 
proposed integrity management program rule. RSPA/OPS discusses how it 
addressed each recommendation in the final rule.
    The Committee discussed how to best identify those segments of a 
pipeline that present the greatest potential hazard to people so that 
operators could focus integrity management efforts on those segments. 
The Committee considered the bifurcated approach

[[Page 69780]]

INGAA had presented in its comments. The Committee discussed whether 
rural buildings, such as rural churches, should be designated as 
Moderate Risk Areas. Much of the meeting was spent on the industry's 
petition for reconsideration. The Committee held an extensive 
discussion on the ``identified sites'' component of the HCA definition, 
focusing on places where people congregate and on buildings containing 
persons of limited mobility. The TPSSC made the following 
recommendations with respect to the definition of and identification of 
HCAs:
    Allow a bifurcated option for building count as part of the 
definition of HCAs.
    RSPA adopted this recommendation into the final rule and modified 
Sec.  192.903 to allow two methods of identifying HCAs. This is 
discussed below in section 3 of Comments to NPRM.
    Address rural buildings in the same manner as any HCA.
    RSPA has adopted this recommendation by modifying the ``identified 
sites'' component of the HCA definition as it relates to outside areas 
where people gather. The definition now differentiates between outside 
areas, open structures, and rural buildings, which provide more 
protection. This is discussed below in Comments to NPRM.
    In the HCA definition, substitute ``public safety officials, 
emergency response officials, or local emergency planning committees'' 
for ``local officials.''
    RSPA accepted this recommendation and modified the ``identified 
sites'' component of the high consequence area definition to 
incorporate this change.
    Define an identified site as any of the following within a 
Potential Impact Circle:
    1. A facility housing persons of limited mobility that is known to 
public safety officials, emergency response officials, or local 
emergency planning committee, and which meets one of the following 
three criteria: (a) Is visibly marked, (b) is licensed or registered by 
a Federal, state, or local agency, or (c) is listed on a map maintained 
by or available from a Federal, State, or local agency, or
    2. An outdoor area where people congregate that is known to public 
safety officials, emergency response officials or local emergency 
planning committee and which is occupied by 20 or more people on at 
least 50 days per year, or
    3. A building occupied by 20 or more people 5 days per week, 10 
weeks in any 12-month period (the days and weeks need not be 
consecutive).
    RSPA accepted this recommendation and modified the ``identified 
site'' component of the HCA area definition. This revision is 
consistent with the Class 3 definition of outside area in Sec.  192.5.
    The Committee discussed whether the criterion for determining the 
population density component of a high consequence area should be 10 or 
20 buildings intended for human occupancy within the impact circle. The 
Committee recommended that RSPA/OPS:
    Use 20 buildings intended for human occupancy occurring within a 
Potential Impact Circle as a criterion for determining high consequence 
areas.
    RSPA adopted this recommendation and modified the definition of 
HCA.
    The TPSSC discussed whether an additional safety margin should be 
applied to the Potential Impact Circle radius calculated using the C-
FER model and recommended that:
    To define an HCA use the C-FER radius without additional safety 
margin to define the Potential Impact Circle, and extend by one 
additional radius on either side of the segment that could potentially 
impact an HCA.
    RSPA adopted this recommendation and modified the definition of HCA 
to incorporate this additional length of pipeline.
    The TPSSC discussed whether the rule should allow an operator to 
use data regarding the number of buildings within 660 feet of the 
pipeline (available now to operators because of the existing definition 
of Class Locations at Sec.  192.5) to extrapolate the building density 
in Potential Impact Circles larger than 660 feet, and what the interim 
period should be for operator to collect the additional data on 
buildings beyond 660 feet. The Committee voted that the rule should:
    Allow a three-year period for operators to use existing house count 
data out to 660 feet to infer the number of houses in impact circles 
exceeding 660 feet in radius.
    RSPA accepted this recommendation and intends to allow operators 
three years to collect actual data and to revise the HCA to reflect 
this data.
    The Committee discussed what assessment requirements should be 
applicable to plastic transmission pipelines and recommended that the 
rule should:
    Allow operators to conduct a reliability analysis as a baseline 
assessment for plastic pipeline, and require appropriate preventive and 
mitigative measures.
    RSPA revised the final rule to require additional preventive and 
mitigative measures for plastic transmission pipelines.
    The Committee discussed the assessment methods and intervals that 
should be required for low-stress pipelines and then voted for RSPA/OPS 
to:
    Use the approach suggested by AGA as described on pages 6 and 7 of 
its April 30, 2003 letter, ``Amendment to Low-Stress Pipeline 
Requirements.''
    RSPA adopted this recommendation and created a new section in the 
gas rule (Sec.  192.941) on low-stress reassessment for pipelines 
operating below 30% of specified minimum yield strength (SMYS). This 
recommendation provides for additional analysis focused on third-party 
damage and increases the frequency of leak surveys as an alternative 
form of reassessment. This is discussed below in section 7 of Comments 
to NPRM.
    The TPSSC discussed whether a requirement to pressure test a 
pipeline to verify its integrity against material and construction 
defects be limited to pipeline segments for which information suggests 
a potential vulnerability. The Committee recommended that RSPA/OPS:
    Incorporate into the rule the concepts of B31.8S pertaining to 
material and construction defects and increased operating pressure.
    RSPA has incorporated ASME/ANSI B31.8S-2001, Managing System 
Integrity of Gas Pipelines, into the regulation.
    The TPSSC discussed the proposed direct assessment requirements and 
ways to ensure that the method provides an understanding of pipeline 
integrity comparable to that provided by other assessment methods. In 
particular the discussion focused on whether it should be allowed as a 
primary assessment method only to address certain threats, and whether 
the assessment intervals should be the same as those allowed for the 
other assessment methods. The TPSSC recommended that the rule:
    Allow direct assessment as a primary assessment method contingent 
only on applicability to the threats and have assessment intervals the 
same as those for other methods, subject to clarification on how 
confirmatory direct assessment fits into the process and relates to the 
NACE Recommended Practice.
    RSPA/OPS has accepted this recommendation and revised the final 
rule to allow direct assessment as a primary assessment method for 
certain threats and to have the same assessment intervals as the other 
assessment

[[Page 69781]]

methods. This is discussed below in section 4 of Comments to NPRM.
    The Committee discussed some of the proposed requirements for 
remediation of anomalies found during an assessment, including whether 
repair criteria for dents located on the bottom of the pipeline should 
be different from those for top dents and whether the presence of 
stress risers or metal loss should affect this decision. The Committee 
voted that RSPA/OPS:
    Modify the proposal to require remediation of dents without stress 
risers in one year to allow treating bottom-side dents as monitored 
conditions if the operator runs the necessary tools to perform strain 
calculations, meets B31.8 strain criteria, and [ensures] that the dent 
involves no corrosion or stress riser.
    RSPA accepted this recommendation and revised Sec.  192.933 to 
address remediation requirements.
    A member of the Committee noted that the proposed waiver language 
did not exactly track the language in the statue. The Committee 
recommended that RSPA/OPS:
    Revise the proposed waiver language to be consistent with the 
language in the statute.
    RSPA/OPS revised the waiver language in Sec.  192.943 to track the 
language in the statute. This is discussed below in section 5 of 
Comments to NPRM.
    The TPSSC discussed how to cost-effectively protect against delayed 
failures from third-party damage and whether additional third-party 
damage prevention methods should be used instead of assessments for 
third-party damage. The Committee recommended that RSPA/OPS:
    Use the language proposed by INGAA, in its April 17, 2003, letter 
(as modified by Committee comments) as the basis for requiring 
additional preventive and mitigative measures to address third-party 
damage.
    RSPA accepted this recommendation and revised the third-party 
damage requirements.
    The Committee discussed how to clarify the requirements for an 
operator to look beyond the HCA segment to address segments outside the 
HCA that are likely to have similar integrity concerns. After 
discussion the Committee voted that the rule should:
    Require that operators use the risk assessment process as described 
in ASME B31.8S as the basis for deciding when actions need to be taken 
for pipeline segments not in HCAs.
    RSPA incorporated this recommendation into the final rule.
    The TPSSC discussed at what frequency and by what means operators 
should report performance measures. The recommendation was to:
    Require operators to submit performance measures electronically 
(instead of merely maintaining the information) on a semi-annual 
frequency.
    RSPA revised Sec.  192.945 to incorporate this recommendation.
    The Committee discussed the proposed rule's treatment of earlier 
integrity assessments to allow only assessments conducted after 
December 17, 1997, to be used as a baseline assessment. The TPSSC 
recommend that the rule:
    Allow, without a time limit, an assessment conducted prior to the 
rule as a baseline assessment as long as the prior assessment 
substantially meets the requirements of the rule, and provide that the 
reassessment for such a segment not be required until December 17, 2009 
to the extent allowed by law.
    For the reasons discussed below in section 4 of Program 
Requirements, RSPA/OPS is allowing as a baseline assessment any prior 
assessment conducted in accordance with the requirements of the subpart 
on integrity management. RSPA/OPS has further revised the rule to 
specify that the reassessment on a covered segment for which a prior 
assessment is credited as a baseline be completed by December 17, 2009.
Discussion on Cost-Benefit Analysis
    The TPSSC met via conference telephone call on July 31, 2003, to 
discuss the draft cost-benefit analysis prepared in support of the 
final rule. RSPA/OPS presented a summary of the benefits and costs of 
the rule. Because of the integrity requirements in the Pipeline Safety 
Improvement Act of 2002 (49 U.S.C. 60109), this rule does not impose 
integrity management requirements from a baseline condition in which no 
such requirements exist. The law required pipeline companies to develop 
and follow integrity management programs. This rule takes advantage of 
the implementation flexibility allowed in the law to focus integrity 
management efforts on the highest risk areas.
    RSPA/OPS estimates that implementing the requirements in the law, 
without any additional flexibility, would cost approximately $11 
billion over 20 years. Using the same basic assumptions, implementing 
the provisions of this rule is estimated to cost $4.7 billion over 20 
years, which is $6.2 billion less than implementation of the law 
without a regulation. The $6.2 billion savings represents a benefit of 
the rule, since the requirements of the law would have to be 
implemented in the absence of regulatory action. RSPA/OPS informed the 
Committee that:
    [sbull] Changes in the definition of HCAs focuses pipeline operator 
resources on areas of high consequence. Class 3 areas that are sparsely 
populated have been deleted.
    [sbull] Confirmatory direct assessment (CDA) is allowed to perform 
assessments at the seven-year intervals specified in the Act. This 
method is not among those listed in the law.
    [sbull] The rule explicitly recognizes the scientific conclusion 
that low-pressure pipelines are more likely to leak than to rupture. 
Outside force damage is therefore a relatively more important threat 
for low-pressure pipelines. The rule provides for assessments and 
actions that emphasize damage protection, leak surveys, and electrical 
surveys to better address the relevant integrity threats.
    The direct safety benefits of the rule will be realized in reduced 
consequences of accidents, including deaths, serious injuries, and 
property damage. RSPA/OPS has estimated the value of this benefit at 
$800 million over 20 years. There are a number of other potential 
benefits of the rule as described to the TPSSC:
    [sbull] Improved ability to site new pipelines in certain high-
volume markets because of the improvements in public confidence. RSPA/
OPS informed the Committee that this benefit is difficult to quantify, 
and would be qualitatively described in the final regulatory analysis.
    [sbull] Averting accidents with larger consequences than any 
experienced to date. The quantitative estimate of this safety benefit 
is based on the historical accident record. Population growth along 
some transmission pipelines puts more people at risk and exposes the 
pipelines to increased chances of third-party damage. Therefore, it is 
possible that accidents larger than any in the historical record could 
occur. This rule will act to significantly reduce the likelihood of 
such accidents, because it is focused on precisely the high population 
areas in which they could occur. RSPA/OPS informed the Committee that 
this benefit would be analyzed further and quantified in the final 
regulatory analysis.
    [sbull] The final rule exceeds the requirements of the law in ways 
that will avert accidents. This includes the requirement that consensus 
standards be used, and that a threat-by-threat analysis be performed to 
ascertain needed protections.

[[Page 69782]]

    [sbull] Avoiding the economic impact of unexpected supply 
interruptions. The Federal Energy Regulatory Commission (FERC) has 
estimated the impact of the 2000 Carlsbad, New Mexico accident on 
California spot gas prices. RSPA/OPS has used this estimate to 
calculate that the increase in gas prices resulted in an economic 
impact to California of approximately $17.25 million per day.
    [sbull] The rule will provide a better technical justification for 
increasing operating pressure in pipelines to alleviate future supply 
crises.
    [sbull] The rule will provide a better technical justification to 
support waivers from existing requirements that mandate replacement of 
pipeline when population increases cause a change in class location. 
Experience may lead to future changes in the existing requirements. For 
now, estimation of the value of this benefit will be based on the use 
of waivers to eliminate pipe replacement after a class location change 
where there is adequate safety justification.
    The TPSSC suggested that a reduction in the time required to return 
pipelines to service after accidents or regulatory shutdowns is another 
benefit of the rule. The premise is that implementation of the rule 
will provide better information about the pipeline. When pipelines are 
ordered shutdown, much of the time is used to gather additional 
information about the pipeline's integrity to support a return to 
service. Implementation of this rule will make more information readily 
available and will lead to less shutdown time. We expect shutdown times 
to be reduced by 50%.
    The TPSSC agreed that the cost estimates presented by RSPA/OPS were 
reasonable. The committee commented that it is reasonable to assume 
that the benefits from implementing the law and the final rule would be 
similar, but that they are also very uncertain.
    The TPSSC commented that the Pipeline Safety Improvement Act of 
2002 imposes restrictions on what can be done within this rule. The 
Committee concluded that RSPA/OPS had reasonably exercised the 
authority it was afforded under the Act. The Committee also recommended 
that provisions in the Act that impose the most hardships--requirements 
to perform assessments at seven-year intervals and to perform 
reassessments before baseline assessments--be revisited in discussions 
with Congress.
    The TPSSC unanimously approved the draft cost-benefit analysis, 
subject to the comments noted above.

Comments to NPRM

    We received over 700 comments from 90 different sources in response 
to the NPRM. Some commenters submitted several comments, each comment 
addressing a different topic in the proposed rule. The commenters were 
as follows:
    Seven (7) Trade associations with members affected by this 
rulemaking: American Gas Association (AGA), American Public Gas 
Association (APGA), Association of Texas Intrastate Natural Gas 
Pipelines, Energy Association of Pennsylvania, Interstate Natural Gas 
Association of America (INGAA), Inline Inspection Association (IIA), 
and Northeast Gas Association (NEGA).
    50 U.S. pipeline operators: AGL Resources, Air Products and 
Chemicals, Inc., Arkansas Oklahoma Gas Corporation, Atmos Energy Corp., 
Baltimore Gas and Electric Company, ChevronTexaco, CMS Panhandle 
Eastern Pipe Line Company, CMS Sea Robin Pipeline Company, CMS 
Trunkline Gas Company, Consolidated Edison Company of New York, 
Consumers Energy, Dominion Delivery, Duke Energy Gas Transmission 
Corporation, El Paso Pipeline Group, Enbridge Energy Company, Enron 
Transportation Services, Equitable Gas Company and Equitrans LP, 
Houston Pipe Line Company, Intermountain Gas Company, Kansas Gas 
Service, Kern River Gas Transmission Company, Laclede Gas Company, 
Metropolitan Utilities District, MidAmerican Energy Company, National 
Fuel Gas Supply Corporation, New Jersey Natural Gas Company, Nicor Gas, 
NiSource Corporate Services, North Shore Gas Company, Northern Natural 
Gas Company, Oklahoma Natural Gas, ONEOK, Paiute Pipeline Company, PECO 
Energy, Peoples Gas Light and Coke Company, PG&E Corporation, Piedmont 
Natural Gas, PSNC Energy, Public Service Electric and Gas Company, 
Puget Sound Energy, Questar Regulated Services, Sempra Energy 
Utilities, South Carolina Pipeline Corporation, Southwest Gas 
Corporation, TXU Gas Company, Vectren Utility Holdings, Inc. Williams 
Gas Pipeline, Williston Basin Interstate Pipeline Company, and Xcel 
Energy.
    One (1) Canadian pipeline operator: TransCanada Pipelines Limited.
    Five (5) state agencies: Florida Department of Environmental 
Protection, Iowa Utilities Board New York State Department of Public 
Service, State of Connecticut Department of Public Utility Control, 
Washington Utilities and Transportation Commission.
    Three (3) advocacy groups: Citizens for Safe Pipelines, Cook Inlet 
Keeper, and Washington State Citizens Advisory Committee on Pipeline 
Safety.
    Three (3) consensus standards organizations: Gas Piping Technology 
Committee (GPTC), NACE International, and Standards-Developing 
Organizations Coordinating Council (SDOCC).
    One (1) Federal agency: National Transportation Safety Board 
(NTSB).
    One (1 ) city/county: Washington City and County Pipeline Safety 
Consortium.
    Two (2) consultant/contractors: Accufacts, and Oleska & Associates.
    Three (3) businesses: Advanced Technology Corporation, 
Controlotron, and Kaempen Pipe Corporation.
    One (1) private citizen: Carol M. Parker.

General Comments

    Most commenters supported the need for integrity management program 
requirements, and provided comments to the proposed rule that focused 
on specific details and language. Most commenters asserted that the 
proposed rule was too complicated and, to ensure safety and ease of 
compliance, should be simplified and clarified.
    Some of the broader comments included one from a private citizen, 
Carol Parker, who asserted that the new pipeline safety law was written 
to ensure ``adequate protection against risks to life and property 
posed by pipeline transportation'' and that RSPA should use this new 
law as a guide to ensure adequate protection. Similarly, the Washington 
State Advisory Committee commented that the new rule should not 
sacrifice rule credibility and enforceability for timeliness, and 
recommended that RSPA slow down the process to ensure proper rule 
development. The NTSB stated that it generally supported the elements 
of the proposed rule including the baseline assessments, threat risk 
assessments, determination of assessment methods, and remediation and 
reassessment provisions. More specific comments are discussed under the 
applicable topic.
    We have organized the comments into the following twelve groups, 
and will summarize both the comments and our responses on an individual 
basis.
1. Need for Clarity and Specificity
2. Applicability (Coverage) of the Rule
3. High Consequence Areas
4. Program Requirements and Implementation, including Integrity 
Assessment Time Frames, Assessment Methods and Criteria
5. Review, Notification and Enforcement Processes

[[Page 69783]]

6. Consensus Standard on Pipeline Integrity
7. Low-Stress Pipelines
8. Remedial Actions
9. Additional Preventive and Mitigative Measures, including, Leak 
Detection Devices and Automatic Shut-off and Remote Control Valves
10. Methods to Measure Program Effectiveness
11. Information for Local Officials and the Public
12. Cost-Benefit Analysis
1. Need for Clarity and Specificity
    Several commenters, including the Public Service Electric and Gas 
Company (PSE&G), maintained that the formatting of the proposed rule 
makes it difficult to follow, which could lead to a lower level of 
understanding and less compliance. PSE&G suggested that the final rule 
be simplified and reformatted, with clearly numbered sections and an 
index. Piedmont Natural Gas recommended the use of several sections to 
present the regulations because the proposed cross-references and 
formatting make the proposed rule difficult to read and understand.
    Some commenters, including Peoples Energy, suggested that we better 
define terms that are subjective and possibly vague. Some of those 
terms included: state-of-the-art, comprehensive additional preventive 
measures, expected future corrosion conditions, critical stage, and 
additional extensive inspection and maintenance programs.
    Numerous other commenters, including Northeast Gas Association, 
Puget Sound Energy, and the Iowa Utilities Board, suggested rewriting 
the rule as a separate subpart of part 192 in a clearer, more 
simplified form.
    Response: RSPA/OPS agrees that the proposed rule was complicated 
and often difficult to follow. There are a large number of interrelated 
requirements. Including all of those requirements under a single 
section of part 192, as was done in the proposed rule, required use of 
many sub-paragraphs and divisions. RSPA/OPS has adopted the suggestion 
that the final rule be rewritten as a separate subpart of part 192.
    The final rule has been recast as new Subpart O, Pipeline Integrity 
Management, of part 192, in which we have consolidated all of the 
requirements applicable to gas transmission pipeline integrity 
management programs. The definition of HCAs, previously Sec.  192.761, 
has been relocated to the new subpart (with changes as described 
below). This revised structure allows each of the major elements of the 
rule to be described in a separate, numbered section. The use of 
subparagraphs and divisions in the final rule is very limited. RSPA/OPS 
believes that the structure of the final rule makes it much easier to 
follow and understand, and will better support compliance by operators.
    The rule has also been revised to improve its clarity and 
specificity. For example, we deleted terms such as ``state-of-the-
art.'' And we specify which ``comprehensive additional preventive 
measures'' an operator must implement. We eliminated the section 
containing the phrase ``expected future corrosion conditions'' in favor 
of referencing an applicable consensus standard. At the time we 
proposed the rule, relevant industry consensus standards were under 
development. These standards have since been finalized and we have 
incorporated them into the rule.
    This rule uses, as did the corresponding rule for hazardous liquid 
pipelines, a mix of performance-based and prescriptive requirements. As 
described in the final rule on integrity management programs for 
hazardous liquid pipelines (65 FR 73832), RSPA/OPS believes that 
performance-based regulation will result in effective integrity 
management programs that are sufficiently flexible to reflect pipeline-
specific conditions and risks. Pipeline conditions vary. It is 
impractical to specify requirements that will address all 
circumstances. In some cases, they would impose unnecessary burdens. In 
others, they might not achieve the desired level of safety. Including 
performance-based requirements is the best means to ensure that each 
pipeline develops and implements effective integrity management 
programs that address the risks of each pipeline segment.
2. Applicability (Coverage) of the Rule--Sec.  192.901 (Formerly Sec.  
192.763(a)(b))
    The proposed integrity management program requirements were 
intended to apply to all gas transmission pipelines. Other gas 
pipelines were not included in the scope of the proposed rule.
    NTSB commented that gathering pipelines in populated areas should 
be included. The New York State Department of Public Service maintained 
that only those gathering pipelines in HCAs and operating above 20% of 
SMYS should be included.
    At the public meetings and advisory committee meeting, participants 
noted that the NPRM and pipeline safety statute did not address plastic 
gas transmission pipelines. At the advisory committee meeting, a 
representative of APGA prepared a handout on plastic transmission 
pipelines. The handout included recommendations from Southwest Gas that 
RSPA/OPS should exclude plastic pipelines from the integrity management 
regulation or, as an alternative, exclude these pipelines from the 
assessment requirements because the assessment methods are not 
applicable to plastic. In addition, the handout noted that the proposed 
additional preventive and mitigative measures for corrosion are not 
applicable to plastic pipe because it is not subject to corrosion. The 
handout suggested that third-party excavation damage is the primary 
threat to plastic pipe.
    Both Cook Inlet Keeper and the Washington Utilities and 
Transportation Commission (WUTC) commended OPS's goal to promote safety 
throughout pipeline systems. They recommended that the proposed rule 
require that lessons learned from assessments on pipeline segments in 
HCAs be applied to all segments of pipeline and all operators. Although 
INGAA agreed with the concept of applying lessons learned to pipeline 
segments outside the scope of the proposal, it recommended modifying 
the requirement to clarify how data and information developed from 
covered segments will be applied to non-covered segments. INGAA 
suggested an approach for applying this concept using the framework of 
standard ASME/ANSI B31.8S. Several industry commenters agreed with 
INGAA, but numerous commenters asserted that expanding the requirements 
of the rule to entire pipelines is inappropriate. NiSource contended 
that an expansion conflicts with the intent of Congress to focus 
resources on high risk areas. NiSource also suggested that the final 
rule should incorporate ASME/ANSI B31.8S as it relates to collection, 
review, and integration of data to update risk assessments.
    Response: The final rule prescribes minimum requirements for 
integrity management programs on any gas transmission pipeline subject 
to Part 192. The requirements do not apply to gas gathering or 
distribution pipelines. Although some requirements are of broad 
applicability, they apply mainly to segments of gas transmission 
pipelines in HCAs. RSPA/OPS agrees with Cook Inlet Keeper and WUTC that 
lessons learned in developing and applying the integrity management 
program in HCAs should be applied to other portions of the pipeline. It 
would not be prudent to fail to address known problems that could 
challenge the integrity of a pipeline simply because they did not occur 
in HCA pipeline segments. The rule requires that all operators evaluate 
and remediate non-

[[Page 69784]]

covered segments of their pipelines that have similar characteristics 
to covered sections on which corrosion is found (Sec.  192.917(e)(5) 
and Sec.  192.927(c)(3)(iii)). The rule further requires that operators 
who qualify for the performance-based option have a procedure for 
applying lessons learned from assessment of covered pipe segments to 
pipe segments not covered. (Sec.  192.913(b)(1)(iv).)
    The rule does not require integrity assessment, but it does require 
evaluation of risk associated with non-covered segments and appropriate 
actions to address those risks. Such a requirement would divert 
resources away from pipeline segments that pose the most risk (i.e., 
those located in HCAs) to those which pose lesser risks. ASME/ANSI 
B31.8S, the consensus standard on Managing System Integrity of Gas 
Pipelines, provides a method by which operators can perform these 
evaluations.
    Although it is necessary to apply lessons learned on covered 
segments to non-covered segments of pipeline, it is equally appropriate 
that knowledge gained in segments of pipeline that cannot affect HCAs 
be used in the evaluation of covered segments. The rule requires this 
as part of an operator's data gathering and integration activities 
(Sec.  192.917(b)). The operators must, at a minimum, evaluate the set 
of data specified in ASME/ANSI B31.8S.
    When RSPA/OPS proposed the integrity management program 
requirements for gas transmission pipelines, it had not considered 
plastic transmission pipelines. The statute does not allow an exemption 
for such pipelines. However, based on the information developed after 
issuance of the NPRM, we recognize that these pipelines typically 
operate at very low pressures and are not subject to corrosion. 
Internal inspection tools are not useful for evaluating the condition 
of these pipelines. Corrosion protection measures are not required 
because plastic does not corrode. Therefore, in the final rule we have 
recognized that these pipelines cannot be assessed by the methods 
allowed for metallic transmission pipelines. An operator of a plastic 
transmission pipeline will have to conduct, on a continual basis, a 
threat analysis to evaluate the threats unique to the integrity of 
plastic pipe. If the analysis shows that the pipeline is susceptible to 
failure from a cause other than third-party damage, the operator must 
conduct a baseline assessment by a method demonstrated to characterize 
the risks, and must apply additional preventive and mitigative measures 
as necessary.
    A government/industry Plastic Pipe Database Committee (PPDC) has 
been formed to develop and maintain a voluntary plastic pipe data 
collection process to support the analysis of the frequency and causes 
of in-service plastic pipe material failures. The PPDC monitors failure 
experience to characterize any failure trends in older plastic pipe 
materials. Thorough analysis of data on plastic pipelines having 
similar fabrication, construction, and operational characteristics will 
alert operators of these pipelines to integrity threats other than 
third-party damage.
3. High Consequence Areas--Sec.  192.903 (Formerly Sec.  192.761)
    The definition of HCAs for gas transmission pipelines was set forth 
in a final rule on August 6, 2002. The definition included Class 3 and 
4 locations, and ``identified sites'', i.e., buildings housing people 
who have limited mobility or are difficult to evacuate and outside 
areas where there is sufficient evidence of people congregating. The 
rule listed ways for an operator to identify these sites, including 
visible marking, licensure or registration by a Federal, State, or 
local agency, knowledge of public safety officials, or a list or map 
maintained by or available from a Federal, State, or local agency.
    The definition generated numerous comments. And, as discussed 
elsewhere in this document, industry trade associations filed a 
petition for reconsideration of the definition. At the public meetings 
following the issuance of the integrity management NPRM, meeting 
participants commented in great detail about problems with the 
definition. At the TPSSC meeting, members discussed the definition and 
issues raised in the petition for reconsideration.
    Comments on the proposed definition of HCAs for gas transmission 
pipelines addressed the complexity of the definition and difficulty in 
identifying HCAs; additional areas to be included; the role of public 
officials in ``identified sites;'' numbers of people congregating in 
outside areas and in ``identified site'' buildings; C-FER model; 
Threshold Radius; system considerations; and calculation of Moderate 
Risk Areas, Potential Impact Circle (PIC), Potential Impact Radius 
(PIR), and Potential Impact Zone (PIZ). The comments on each of these 
topics are discussed below.

The Definition's Complexity and Difficulty in Identifying HCAs

    The high consequence area definition included Class 3 and 4 areas 
because these areas are currently defined in the gas pipeline safety 
regulations. The definition also included ``identified sites'' and a 
list of methods for identifying them. These sites included facilities 
with people who are confined, of limited mobility or would be difficult 
to evacuate, and outside areas and buildings where there is evidence 
that at least 20 or more people congregate on at least 50 days in any 
12-month period.
    In the NPRM for integrity management program, RSPA/OPS proposed to 
add another area to the definition--a circle of Threshold Radius 1,000 
feet or larger that has a cluster of 20 or more buildings intended for 
human occupancy.
    In their petition for reconsideration of the HCA definition, the 
petitioners argued that RSPA should clarify the definition, 
particularly with regard to ``identified sites,'' because the 
definition is so broad and vague as to make compliance impractical. 
Comments at the post-NPRM public meetings also suggested that the 
definition needed to be clarified.
    Many commenters noted the complexity of the proposed expanded 
definition and asked that it be simplified. Baltimore Gas and Electric 
(BG&E) asserted that the number of variables and data requirements 
related to the definition make it unworkable. BG&E explained that 
distribution system operators maintain data on population and buildings 
near their pipelines, but would have difficulty identifying facilities 
with persons who are confined or of limited mobility and areas where 
people congregate. The company recommended that the definition only 
reference verifiable criteria in determining areas to be covered under 
the integrity management requirements. Northeast Gas Association 
requested clarification on whether the proposed expanded definition 
only applied to large diameter, high pressure pipe.
    Dominion supported the use of current Class designations to define 
HCAs because it believes smaller pipeline companies do not have access 
to sophisticated geographic information systems (GIS). The State of New 
York also supported the use of the current Class designations, 
supplemented by the use of the C-FER model to identify HCAs outside of 
Class 3 and 4 areas.
    INGAA argued that the proposed addition to the HCA definition added 
complexity and additional practices that would not improve pipeline 
safety. INGAA proposed a bifurcated option, which would allow the 
operator some flexibility in determining its cumulative HCA sites. 
Under this proposal, an

[[Page 69785]]

operator could choose from two approaches to determine HCAs. Both 
approaches would require that an operator identify potential HCAs for 
certain ``identified sites'' located within a Potential Impact Circle. 
In addition to the ``identified sites,'' the operator would either 
identify the remaining HCAs by selecting all Class 3 and 4 areas or by 
determining all Potential Impact Circles containing 20 or more 
buildings intended for human occupancy. Potential Impact Circles would 
be based on the C-FER model. When the size of the pipeline requires 
that the radius is greater than 660 feet, INGAA's proposal would allow 
prorating the number of buildings in the circle based on an increased 
circle size. INGAA's proposed proration scheme would allow operators 
additional time to collect the expanded population data--until as late 
as 2007.
    AGA supported this approach because it is simpler, allows operators 
to use existing data from house count surveys, and provides safety 
benefits to unsheltered areas. At least 30 other commenters endorsed 
this alternative approach.
    Response: RSPA/OPS has adopted a bifurcated definition, as 
suggested by INGAA. It gives an operator two options to define HCAs. In 
both options ``identified sites'' are treated the same. However, an 
operator will now be allowed to identify the HCAs associated with high 
population density either by including all Class 3 and 4 areas or by 
counting the residences within a potential impact circle to determine 
whether the threshold number is present. Changes made to the 
``identified sites'' definition are described further below. We agree 
that this approach is less complex, allows flexibility to operators 
(particularly local distribution companies who may wish to designate 
all Class 3 and 4 areas), and better focuses on areas where people 
could be most affected by pipeline ruptures, fires, and explosions.
    RSPA/OPS has decided to allow operators to prorate the number of 
buildings in Potential Impact Circles larger than 660 feet in radius 
for a period of three years. We believe that the recommended five-year 
period for proration is too long, but acknowledge that collecting all 
of the additional data in one year would be an unreasonable resource 
burden. Operators now have data on the number of buildings located 
within 660 feet from their pipelines because they have needed this 
information for identifying Class Location areas pursuant to Sec.  
192.5. The three-year period is adequate for operators to gather 
additional information for the large-diameter, high-pressure pipelines 
for which Potential Impact Circle(s) will exceed 660 feet.
    RSPA/OPS expects that many, perhaps most, operators will follow the 
Potential Impact Circle option for defining HCAs. Under this approach, 
an operator would calculate the heat affected zones along its pipeline 
that would result from a pipeline rupture. An operator would determine 
the radius of the Potential Impact Circle for the pipeline, identify 
segments of pipeline within a Potential Impact Radius of ``identified 
sites,'' and identify segments of pipeline having 20 or more residences 
within a Potential Impact Circle. Such segments would be HCAs, and the 
length of pipeline included in the HCA would be the pipe within the HCA 
plus the length of pipe extending one Potential Impact Radius in both 
directions beyond the HCA.
    For transmission pipelines operating at low pressures, like much of 
the pipeline operated by distribution companies, the radius of the 
Potential Impact Circle calculated with the C-FER model will be small. 
For example, the radius for a 6-inch diameter pipeline operating at 150 
psi would be 50 feet. It is unlikely that 20 buildings intended for 
human occupancy could be found in circles of such small radius. It is 
also less likely that ``identified sites'' will be found within the 
circles as the radius decreases. As a result, using the Potential 
Impact Circle option will tend to exclude much low-pressure pipeline 
from the assessment requirements of this rule. Because accidents along 
these pipelines in developed areas can affect people and property, the 
rule requires an operator of a low-stress pipeline in these developed 
area to take additional preventive and mitigative actions.

Additional Areas

    Several commenters suggested adding other sites as HCAs. The 
Florida State Clearinghouse, the Washington City and County Safety 
Consortium, and the New York State Department of Public Service all 
asserted that certain critical infrastructure facilities be included as 
HCAs. These included, but were not limited to, interstate interchanges, 
bridges, tunnels, certain railway facilities, electric transmission 
substations, drinking water plants, and sewer facilities. They asserted 
that impacts to these types of facilities could detrimentally impact a 
wide range of people. The Washington City and County Safety Consortium 
further contended that environmentally sensitive areas, particularly 
those critical to endangered species, should be included as well.
    Response: RSPA/OPS has not included these additional areas in the 
final rule. We addressed comments such as this in the rulemaking on 
high consequences areas. Other than the issues that had been raised in 
the petition for reconsideration, and the areas in the NPRM for 
integrity management program requirements we proposed to add, or 
requested comment, we did not open the final definition up for changes. 
When we issued the final rule defining these areas, we agreed that 
impacts to critical infrastructure could have detrimental impact but 
that such impacts would not likely include death or serious injury. A 
major purpose of the integrity management rule is to focus the highest 
level of operator attention on those portions of its pipeline that can 
have the most severe safety consequences, i.e., can cause death and 
injury.
    However, to protect vital infrastructure, the rule provides for 
applying lessons learned through integrity management to areas outside 
HCAs. The ASME/ANSI B31.8S process provides that operators use their 
risk assessments to guide them in applying these lessons. Proper risk 
assessments will identify portions of pipeline that have a higher 
likelihood of failure.
    Similarly, as we explained when we finalized the definition of HCAs 
(67 FR 50824), we did not include environmentally sensitive areas in 
the definition. The impact of gas pipeline accidents on such areas is 
expected to be significantly less than a similar accident involving a 
hazardous liquid pipeline because of the different nature of gas and 
hazardous liquids.

Public Officials and Identified Sites

    For the ``identified sites'' component of the high consequence area 
definition, the definition listed various means by which an operator 
could identify these areas. The list included a site being visibly 
marked, being licensed or registered by a Federal, State, or local 
agency, being known to public safety officials or being on a list or 
map maintained by or available from a Federal, State, or local agency. 
In the preamble to the NPRM, RSPA/OPS invited comment on whether we 
should use the term public safety officials and/or emergency response 
officials instead of public officials (68 FR 4278, 4295).
    In the petition for reconsideration of the high consequence area 
definition, petitioners objected to relying on public safety officials 
for identifying these sites because these officials might not be able 
to convey accurate information.
    PECO, PG&E, and Peoples Energy all concurred that the phrase 
``public safety

[[Page 69786]]

officials and/or emergency response officials'' was preferable to 
``public officials.'' PG&E maintained the term ``public officials'' was 
too broad and provided too much variance for interpretation.
    Both the Washington State Advisory Committee on Pipeline Safety and 
the Washington City and County Pipeline Safety Consortium suggested 
that operators work with local cities or municipalities to identify 
additional HCAs within their territories. They asserted that the cities 
and municipalities have the best information on facilities and on 
growth trends in their areas and would be in the best position to 
identify HCAs.
    The Association of Texas Intrastate Natural Gas Pipelines and 
several other commenters asserted that the requirement to identify a 
site under the HCA definition by reference to commercially available 
databases is not reasonable. Kern River suggested that the rule needs 
to be expanded to define the exact process to follow to identify 
locations of people with limited mobility. Kansas Gas Service commented 
that the methods to identify these sites are unduly burdensome and 
impractical.
    Several commenters sought more specificity in the procedure to 
identify outdoor areas and buildings requiring consideration as 
``identified sites,'' and recommended that local public safety 
officials be relied upon in making these identifications.
    Discussion at the public meetings and the May 2003 meeting of the 
advisory committee further highlighted industry concerns about locating 
buildings housing populations of limited mobility and areas where 
people congregate. The TPSSC recommended that local emergency planning 
committees (LEPC) be considered in addition to public safety and 
emergency response officials and that local public safety and emergency 
response officials or LEPCs be relied on as a principal source of 
information in identifying buildings containing populations of limited 
mobility. The TPSSC recommended that the focus for such buildings be 
those known to these local safety officials and meeting one of the 
tests: Be visibly marked, be licensed or registered, or be listed on a 
government map.
    Response: RSPA/OPS agrees that specifying public safety officials, 
emergency response officials, or local emergency planning committees is 
clearer than the term ``public officials'' for purposes of this rule. 
These are the officials and agencies charged with protecting the health 
and safety of the community, and they are most likely to have 
information relevant to identifying and protecting areas where people 
could be affected by pipeline accidents. Other employees of local 
governments, who might be considered ``public officials,'' would be 
less likely to know the relevant information. The final rule has been 
revised to use this more focused terminology, and to make these 
officials a principal source of information regarding places where 
people congregate and buildings housing populations of limited 
mobility. RSPA/OPS is working to inform local emergency responders 
about the need to be knowledgeable about the ``identified sites.'' This 
change is consistent with the advisory bulletin RSPA/OPS issued on July 
17, 2003.
    The ``identified sites'' component of the definition included a 
list of methods operators could use to identify facilities with persons 
of limited mobility. However, the definition caused consternation 
because many operators saw it as an exclusive list. To address this 
concern, in the advisory bulletin issued on July 17, 2003 (68 FR 42458) 
we explained that it was never intended that operators perform an 
exhaustive search of every possible source of information. Rather, 
operators who consult public safety or emergency response or planning 
officials who indicate that they have knowledge of the ``identified 
sites'' need not do more (68 FR 42458, 42460).
    In the final definition, we have clarified that local safety 
officials are the principal source of information on places where 
people congregate and buildings housing populations of limited 
mobility. This change is consistent with the guidance in the advisory 
bulletin issued on July 17, 2003. If these officials do not have the 
information to identify these sites, then an operator must use at least 
one of the other methods, such as visible marking or registration lists 
to identify the sites. These methods are explained in the new Sec.  
192.905 on how an operator is to identify a high consequence area. 
Rather than include these methods in the high consequence area 
definition in Sec.  192.903, we moved them to the new section that 
explains the methods for identifying these sites. For outdoor areas, 
the final rule also relies on the knowledge of local safety officials 
to identify these areas.

People in Outside Areas and in Identified Site Buildings--Sec.  192.903 
(Formerly Sec.  192.763(i))

    In the petition for reconsideration of the high consequence area 
definition, petitioners argued that RSPA should clarify the definition, 
particularly with regard to ``identified sites,'' because the 
definition is so broad and vague as to make compliance impractical. 
Petitioners noted that the definition references two standards for 
identifying places as HCAs because people congregate at those places. 
Petitioners requested that for consistency the same standard be used as 
the one used in the Class 3 definition, i.e., 20 or more persons on at 
least 5 days a week for 10 weeks in any 12-month period.
    We had included rural churches in the example of outside areas 
under the HCA definition. In the petition for reconsideration, 
petitioners contended that the definition would pick up isolated and 
infrequently occupied buildings. In the Preamble to the NPRM on 
integrity management program requirements, RSPA/OPS acknowledged it did 
not know how many rural buildings would be covered and requested 
comment on whether to include these buildings, instead, as Moderate 
Risk Areas. The definition did not require a minimum number of confined 
or mobility-impaired people needed to occupy a facility. The definition 
did require that for outside gathering areas, there be 20 or more 
persons on at least 50 days in any 12-month period. The NPRM did not 
propose a new threshold for the number of persons needed to occupy an 
identified site. Nonetheless, we received a variety of comments on the 
number that had been included in the final definition.
    Citizens for Safe Pipelines was adamant that Congress intended to 
protect sites similar to the Carlsbad accident site and, as support, 
referenced statements made by members of Congress. Citizens for Safe 
Pipelines contended that the definition is under-inclusive of places 
where pipelines should be inspected. Cook Inlet Keeper, along with the 
Washington City and County Pipeline Safety Consortium commented that 
the threshold for persons in outside areas of congregation should be 10 
instead of 20. Accufacts supported having the outside area threshold as 
10 instead of 20, but keeping the building threshold at 20. Most of 
industry sided with INGAA which supported 20 or more persons in outside 
areas of congregation with a much stricter frequency of 5 days a week, 
10 weeks a year.
    INGAA also proposed that we change the ``identified sites'' 
component to differentiate between rural buildings and outside areas, 
and to use different occupancy rates. The definition had grouped rural 
buildings and outside areas together, subject to a minimum use by 20 
persons on at least 50 days in

[[Page 69787]]

any 12-month period. INGAA proposed changing the HCA definition to 
define an identified site as a building occupied by 50 or more persons 
at least 5 days a week, 10 weeks a year with the days and weeks not 
necessarily consecutive, and as an outside area that is small, well-
defined and occupied by 20 or more persons at least 5 days a week, 10 
weeks a year with the days and weeks not necessarily consecutive.
    Industry generally shared INGAA's position that the building should 
be occupied by 50 or more persons at least 5 days a week 10 weeks a 
year and the buildings would not be limited to those containing persons 
of limited mobility. Both Accufacts and Cook Inlet Keeper said the 
threshold number of persons should be no less than what was specified 
in the HCA definition.
    Response: When RSPA/OPS defined the number of people needed to 
gather in an outside area, we intended that areas, like the camping 
area in Carlsbad, would be covered. The number of people and the 
frequency of use was intended to pick up areas used for recreation on 
weekends. We did not open for discussion the threshold number of people 
needed to occupy a building with persons of limited mobility or to 
gather in an outside rural gathering area or building. The definition 
did not specify an occupancy rate for buildings with persons who would 
be hard to evacuate, and specified 20 persons for a rural building or 
outside area. Nor did we open for comment the specified frequency in an 
outside area (50 days in any 12-month period). We have not changed the 
occupancy threshold in these outside gathering areas.
    However, we reopened the issue of how to treat rural buildings. In 
the final rule, we have modified the definition of outside gathering 
areas to address the rural building issue. The identified site 
definition in the final rule includes an outside area or open structure 
that is occupied by twenty (20) or more persons on at least 50 days in 
any twelve (12)-month period. The days need not be consecutive. 
Examples of these areas would be beaches, playgrounds, recreational 
facilities, camping grounds, outdoor theaters, stadiums, recreational 
areas near a body of water, or areas outside a rural building such as a 
religious facility where 20 or more people congregate regularly for 
bazaars or civic activities at least 50 days a year.
    We did not change the occupancy threshold for these outside areas 
and open structures. A threshold of 10, as recommended by several 
commenters, is too low to be practical and would lose the focus on 
higher consequence areas. Current regulations for protecting outdoor 
areas in which people congregate (i.e., by designating them as Class 3 
areas) use a threshold of 20 persons, and this threshold is consistent 
with that practice. The high consequence area definition differs from 
current practice in using a criterion of 50 days per year, which need 
not be consecutive, rather than 5 days per week and 10 weeks per year. 
This recognizes the patterns by which people congregate, including 
weekend use of outdoor areas. This frequency is intended to pick up 
areas similar to the camping area where the Carlsbad accident occurred, 
where local officials know that people gather regularly.
    To further address the rural building issue, the identified site 
definition in the final rule has been revised to differentiate between 
outside open structures and rural buildings. The definition in the 
final rule includes buildings housing 50 or more people 5 days per week 
and 10 weeks per year (the days and weeks need not be consecutive). 
This modification is intended to pick up buildings outside populated 
areas where people gather during the week, or on weekends for 
recreational activities. Because buildings provide some protection from 
the effects of a pipeline accident, RSPA/OPS finds it appropriate that 
the threshold be based on a higher number of people and occupancy 
criteria consistent with current class location regulations. This will 
allow operators to make maximum use of the data they already have 
regarding buildings containing concentrations of people, and further 
reduce the burden of implementing this rule.
    The identified site component also included buildings housing 
people who would be difficult to evacuate or are of limited mobility. 
The definition did not include an occupancy threshold for those 
buildings. We have not modified that component of the definition, 
rather we are relying on the knowledge of local emergency officials.

C-FER Model, Potential Impact Circle (PIC), Potential Impact Radius 
(PIR), and Potential Impact Zone (PIZ) Calculations, and Threshold 
Radius

    Many comments related to the proposed use of the C-FER model and 
the various other calculation methods referenced in the NPRM. The high 
consequence area definition had been based on the heat affected zone 
from a rupture calculated using the C-FER model, with an added margin 
of safety--thresholds of 300 feet for small-diameter, low-pressure 
pipelines, and 1,000 feet for higher-pressure, larger-diameter 
pipelines. The NPRM further proposed to add populated areas at 
distances greater than 660 feet from large-diameter, high-pressure 
pipelines. The C-FER model used a heat flux of 5,000 Btu/hr/
ft2. RSPA/OPS has questioned whether a more conservative 
heat flux rate of 4,000 Btu/hr/ft2, the heat flux rate used 
in the liquefied natural gas regulations (Part 193), should be used 
instead.
    The proposed regulations also included calculations for determining 
the Potential Impact Radius of a covered segment, for determining the 
Threshold Radius associated with the Potential Impact Radius, and for 
identifying the Potential Impact Circle(s) and Potential Impact Zone(s) 
for the pipeline.
    A number of commenters, such as Consolidated Edison and the Iowa 
Utilities Board, suggested that calculations should be based on the 
maximum operating pressure and not on the Maximum Allowable Operating 
Pressure (MAOP).
    Several commenters noted that the term, ``diameter,'' should be 
clarified as inside diameter, outside diameter, or nominal diameter and 
pressure should be clarified as gage or absolute. Consolidated Edison 
suggested that the PIR formula for natural gas should be simplified to 
r = 0.69d[radic]p. Air Products suggested operators be allowed to 
rederive the C-FER model considering product, size of pipeline, and 
operation of emergency flow restricting devices (EFRDs).
    Several commenters supported the use of the C-FER model. Williston 
Basin asserted the model was reliable and should be used over the full 
spectrum of pipeline conditions.
    Northeast Gas Association, Gas Piping Technology Committee, Peoples 
Energy and several other commenters contended that there was no 
justifiable reason to impose an additional safety margin on top of the 
C-FER calculation. In contrast, NTSB argued that an adequate and 
uniform safety margin should be applied for all pipelines and noted 
that the farthest building burned from the Edison, NJ rupture would be 
within the 1,000 foot threshold. NTSB further suggested that RSPA/OPS 
consider the effects of horizontal jetting along the pipeline as 
demonstrated at the Carlsbad, New Mexico rupture site.
    Panhandle Eastern, Williams, and other commenters contended that 
utilizing 5,000 BTUs in the equation was appropriate and there was no 
technical basis for utilizing 4,000 BTUs. The State of New York alleged 
that 5,000 BTUs is too high and the value should be an appropriate 
value to

[[Page 69788]]

eliminate the possibility of fatality and ignition of protective wooden 
structures.
    A large number of commenters were opposed to the use of a Threshold 
Radius, and asserted that its use is unjustified and with no technical 
basis. Northeast Gas Association commented that the wording is 
confusing and asked for clarification as to whether the Threshold 
Radius becomes 1,000 feet when the PIR exceeds 660 feet and when the 
diameter is also 36 inches and the pressure is 1,000 psig or greater. 
The Iowa Utilities Board concurred that the PIC and Threshold Radius 
should be based on the distance of the actual hazard and not on 
arbitrary distances that include areas outside of the Potential Impact 
Radius. The Iowa Utilities Board further contended that burdens on 
small pipelines and operators should be minimized. PECO asked for 
additional clarification as to whether the radius of all Class 3 and 4 
locations is effectively 1,000 feet.
    AGA and several operators, including Baltimore Gas and Electric, 
suggested that operators of pipelines operating below 30% SMYS should 
not be required to go beyond the actual impact zone calculations in 
their identification of HCA areas. Laclede Gas stated that there should 
be no margin above the C-FER calculation, especially for pipelines 
operating below 30% SMYS.
    Response: The appropriateness of the C-FER model was the subject of 
considerable discussion at the public meetings held during the comment 
period on the proposed rule. As a result of these discussions and 
comments to the docket, RSPA/OPS has concluded that the C-FER model is 
sufficiently conservative for use in the screening process to identify 
HCAs. RSPA/OPS believes the model adequately reflects the distance, 
lateral to the pipeline, at which significant effects of accidents will 
occur. In the final rule, we have adopted the model as the basis for 
calculating Potential Impact Circles under the bifurcated option for 
defining HCAs (discussed in prior section) with the addition of the one 
radius at either end (discussed below).
    Discussion at the public meetings and with the advisory committee, 
and analysis of recent pipeline accidents, also identified that 
pipeline accidents have sometimes affected an elliptical area, with the 
long axis of the ellipse along the pipeline. The NTSB noted that this 
likely results from horizontal jetting in the direction of the 
pipeline. The elliptical nature of the burn pattern means that the C-
FER radius is not always conservative in identifying the maximum 
distance from a potential pipe rupture, measured along the pipeline, at 
which the effects from the rupture will be felt. Following careful 
analysis of the burn patterns near pipeline ruptures, RSPA/OPS 
determined that it is appropriate to add an additional length of 
pipeline equal to the C-FER radius on either side of a high consequence 
area, i.e., increase its extent along the pipeline, rather than 
increase the lateral distance. INGAA concurred with this approach. We 
have incorporated this this approach into the final rule. Where 
Potential Impact Circle(s) are used to define HCAs, the pipeline 
segment in the high consequence area extends from the outermost edge of 
the first circle to the outermost edge of the last contiguous circle. 
This is illustrated in Appendix, Figure E.I.A to the final rule. Under 
the proposed rule, the segment would have been limited to the pipe 
between the centers of these circles.
    The concept of Threshold Radius has been eliminated from the final 
rule. This concept was intended to apply some margin to C-FER 
calculations and to simplify the identification of HCAs. As described 
above, RSPA/OPS is convinced that the C-FER model is conservative 
enough for this purpose. We are also convinced by the comments that the 
use of Threshold Radius complicated, rather than simplified, the 
identification of HCAs. With the elimination of this approach, pipeline 
segments are included or not included on the basis of the calculated 
distance of the actual hazard, as recommended by many commenters.
    RSPA/OPS has not adopted the suggestion that maximum operating 
pressure, instead of MAOP, be used in C-FER calculations. MAOP reflects 
the pressure at which the pipeline can be operated, and thus the hazard 
that could be experienced. This is an inherent conservatism in the C-
FER model, and has likely contributed to the successful validation of 
the equation against accident experience.
    The final rule specifies that nominal pipeline diameter is to be 
used in C-FER calculations. It also provides, as did the proposed rule, 
that a different constant factor must be used when making the 
calculation for gases other than natural gas, and refers to ASME/ANSI 
B31.8S for this determination. RSPA/OPS does not agree that further 
derivation of a unique equation for other gases is necessary.

System Considerations

    Numerous operators, including Peoples Energy, Houston Pipeline and 
Puget Sound, asked for clarification on the need to do additional 
studies or calculations if and when they deem their entire systems to 
be HCAs. They asserted there would be no need for the additional effort 
if all parts of their system were designated as HCAs and any additional 
effort would be a waste of company resources and time. Oleska and 
Associates shared this sentiment and recommended allowing operators to 
classify pipelines as being in an HCA without going through any 
analysis.
    The Iowa Utilities Board commented that the rule should allow a 
pipeline operator to exclude its own facilities when determining if 
pipeline is in a high consequence area.
    Response: RSPA/OPS agrees that further analysis to identify HCAs is 
not necessary if an operator elects to treat its entire system as a 
high consequence area. The final rule requires that identification of 
HCAs include documentation of the Potential Impact Radius ``when 
utilized.''
    The high consequence area definition, as modified by this rule, 
focuses on identifying areas where large numbers of people could be at 
risk from a pipeline rupture. RSPA/OPS expects that pipeline operator 
facilities should be treated the same way as other facilities. The only 
operator facilities that could affect the determination are facilities 
in which more than 20 operator employees gather for the number of days 
appropriate to the type of gathering place (i.e., at least 50 days per 
year if outdoors, 5 days per week in at least 10 weeks per year if 
indoor). The number of such facilities is expected to be small. Where 
they exist, however, RSPA/OPS believes it is appropriate to provide 
consideration of those gatherings in the same manner as for gatherings 
of non-operator personnel.

Moderate Risk Areas (MRAs)

    The NPRM proposed to include Moderate Risk Areas, areas located 
within a Class 3 or 4 location but not within the Potential Impact 
Zone. These areas would require less frequent assessment or enhanced 
preventive and mitigative measures. In the preamble to the NPRM, RSPA/
OPS requested comment on two issues related to these areas:
    [sbull] Comments on designating rural buildings, such as rural 
churches, as Moderate Risk Areas instead of as High Consequence Areas 
(68 FR 4278, 4296).
    [sbull] Comments and cost information on an option to not require 
an assessment of a segment located within a Moderate Risk Area, but, 
rather, to require enhanced preventive and mitigative measures on the 
segment (68 FR 4278, 4284). The premise was that if houses are mostly 
clustered in one area of a

[[Page 69789]]

Class 3 rectangle, a pipeline failure in an area beyond the cluster may 
have little, if any, impact on the area with the cluster of homes.
    Comments on MRAs ranged from urging elimination to full support for 
their use. Williston Basin and National Fuel recommended eliminating 
MRAs because they require significant resources and provide few safety 
benefits. Both the Northeast Gas Association and Kern River saw 
potential value in MRAs but suggested their use and implementation 
should be optional. PECO recommended that the MRA definition be 
clarified because it was unclear when buildings should or should not be 
designated as MRAs when they are located in HCAs.
    Northeast Gas Association responded that rural buildings, such as 
churches, in Class 3 and 4 areas, should be designated as MRAs whether 
or not they fall within an impact circle and that such areas should be 
subjected to less frequent assessment and lesser mitigation 
requirements. Several other industry commenters concurred, including 
Southwest Gas and Paiute. PG&E would not support the inclusion of 
churches in the examples of outside areas.
    Taking the opposite position, the Washington City and County 
Pipeline Safety Consortium commented that if such facilities 
incorporate outside areas that are HCAs fall under the definition of an 
HCA, then such rural churches should be captured in the HCA definition.
    Vectren and PG&E noted that areas outside the Potential Impact 
Zones have little probability of being affected by a failure and 
concurred with the suggested option. Northeast Gas Association, 
Southwest Gas Corporation, and other commenters maintained that if MRAs 
remain in the regulation, these areas should be subject only to 
enhanced preventive and mitigative measures.
    Response: The concept of Moderate Risk Areas is not included in the 
final rule. This concept was intended to address areas that met the 
definition as HCAs, but because the areas were more remote and less 
populated, the potential risk of an accident was less than in other 
HCAs. The likelihood of this occurring has been reduced, or eliminated, 
by the changes made in the definition of HCAs. These areas are defined 
in the final rule based on the calculated hazard for operators using 
the Potential Impact Circle option. Additional margin, in the form of 
threshold radii, designation of all Class 3 and 4 areas, or an 
arbitrary margin applied to C-FER calculations, has been eliminated. 
Accordingly, all areas meeting the definition of HCAs require treatment 
as such, and no category of reduced actions is needed.
    As explained in the section on ``identified sites,'' we have 
modified the definition of HCAs to clarify the differences between 
outside open structures and rural buildings. In both cases the 
occupancy threshold is 20 people. For rural buildings, people must 
congregate five days a week for at least ten weeks in year as in the 
current class location 3 definition. For open structures and outside 
gathering areas, people must congregate at least fifty days in a year.
4. Program Requirements and Implementation, Including Integrity 
Assessment Time Frames, Assessment Methods, and Criteria
    The topics covered in this section encompass the majority of the 
comments that addressed the requirements for and implementation of an 
integrity management program. We have grouped in this subsection 
comments addressing general program requirements and compliance time 
frames, baseline assessments and their quality, the use of prior 
assessments, the requirements associated with using Direct Assessment, 
Confirmatory Direct Assessment, and Internal Corrosion Direct 
Assessment, reassessment intervals and overlap, pressure testing 
requirements, cyclic loading, ERW pipe seam issues, and training 
requirements.
    Time Frame for compliance. The proposed rule required operators to 
identify all covered segments within one year from the rule's effective 
date. Northeast Gas Association asked that operators be allowed two 
years after the final rule to identify all pipeline segments and 
conduct a risk analysis.
    Response: The statute requires that RSPA/OPS issue regulations 
prescribing integrity management program standards. These regulations 
must require operators to conduct a risk analysis and adopt an 
integrity management program no later than 24 months after the date of 
enactment, i.e., by December 17, 2004. Therefore, RSPA/OPS does not 
have the flexibility to allow operators two years to complete the 
segment identification. RSPA/OPS has tried to accommodate concerns 
about the time frame for developing a program through use of the 
framework concept.
    Framework: The proposed rule required an operator to develop and 
follow a written integrity management program within one year from the 
effective date of a final rule. However, the proposal allowed the 
operator to begin with a framework addressing each of the required 
program elements. Puget Sound Energy suggested that the requirement for 
a framework should be deleted. The company commented that a framework 
is either an additional document above and beyond the integrity 
management plan or is telling the operator how to develop a plan. The 
company noted that the term is used in ASME/ANSI B31.8S as an umbrella 
for the elements of a plan and not to describe a separate document. The 
Northeast Gas Association requested that a rule have enough flexibility 
to allow operators the time necessary to develop a thorough and 
effective plan. The Association further commented that it may not be 
possible for operators to develop a plan within the time frame 
specified in the proposed rule.
    Response: The intent of allowing a framework was to acknowledge 
that an operator cannot develop a complete, fully mature integrity 
management plan in a year. Nevertheless, it is important that an 
operator have thought through how the various elements of its plan 
relate to each other early in the development of its plan. The 
framework serves this purpose. Each operator is required to develop a 
framework within one year that describes the process for implementing 
each program element, how relevant decisions will be made and by whom, 
and a time line for completing the work to implement the program 
element. It need not be fully developed or at the level of detail 
expected of final integrity management plans. The framework is an 
initial document that evolves into a more detailed and comprehensive 
program. A separate document is not necessary. For some operators 
(e.g., those with only a few miles of covered pipeline) it may be 
possible to prepare a fully-developed integrity management plan within 
a year. In that case, no separate framework is required. The discussion 
of the framework in the final rule has been modified to reflect these 
expectations.
    Communications Plan: One of the proposed elements of an integrity 
management program was a communications plan that includes the elements 
from ASME/ANSI B31.8S. Northeast Gas Association questioned the need 
for a communications plan requirement because a consensus standard on a 
Recommended Practice for Pipeline Public Awareness Programs is now 
being developed under the auspices of the American Petroleum Institute 
(API).
    Response: This rule requires that integrity management plans 
include communications plans that follow the

[[Page 69790]]

guidelines in ASME/ANSI B31.8S, a standard that has been incorporated 
by reference into the final rule. Industry and government 
representatives working on the API standard are aware of the ASME/ANSI 
B31.8S guidelines, and RSPA/OPS expects that the final API standard 
will not conflict with them. RSPA/OPS will consider adoption of the API 
standard, for public awareness, not IMP communications, including 
whether changes to the communication provisions in this rule are 
appropriate, when that standard is approved.
    Best Practices. Northeast Gas Association commented on proposed 
requirements that operators adopt ``best practices.'' The Association 
noted that the best practices for one company are not always applicable 
to other companies, because of the variability in system 
configurations, physical pipeline attributes, and business 
perspectives. Northeast Gas recommended elimination of all references 
to incorporation of best practices.
    Response: RSPA/OPS recognizes that practices applicable at one 
operator might not be as useful or effective at another. Nevertheless, 
RSPA/OPS believes that it is important that operators learn from the 
experience of the industry at large. The standards development process 
is a means of combining industry experience to identify lessons that 
should be applied to other operators. RSPA/OPS has modified the final 
rule to rely on that process. The rule requires that practices in ASME/
ANSI B31.8S be used. The consensus process of gathering, reviewing, and 
publishing best practices in a manner suitable for use at all operators 
should resolve the applicability questions.
    Baseline and Prior Assessments. The proposed rule allowed an 
assessment conducted up to five years before the date of enactment of 
the Pipeline Safety Improvement Act of 2002 as a baseline assessment. 
The Act was signed into law on December 17, 2002. The proposed rule 
established time periods for the baseline assessment. If the assessment 
were done by pressure test or internal inspection, the operator would 
have to complete the baseline by December 17, 2012, with 50% of the 
highest risk pipe being done by December 17, 2007. However, if the 
segment were in a Moderate Risk Area, the assessment would have to be 
done by December 17, 2015. If the operator used direct assessment, the 
baseline would have to be done by December 17, 2009, with 50% of the 
highest risk segments assessed by December 17, 2006, or by December 17, 
2012 if it was in a Moderate Risk Area.
    Southwest Gas Corporation and Paiute Pipeline noted there was no 
provision to incorporate new pipelines into an integrity management 
plan and recommended that for pipelines installed after December 17, 
2002, the installation pressure test be accepted as the baseline 
inspection. Northeast Gas Association supported the proposed 
requirement that 50% of the facilities posing the highest risk be 
baseline-assessed during the first half of the assessment cycle. 
Dominion commented that the proposed language is not clear about when a 
baseline assessment is complete. It suggested the baseline assessment 
start when the first inspection tool is run and that the start of the 
reassessment interval would be when the company runs the final 
assessment tool, analyzes the data from the final tool report, and 
remediates all immediate indications for the baseline assessment.
    Several commenters noted that the date for prior assessments was 
incorrectly listed as 2007 rather than1997. El Paso asserted there is 
no technical basis for the five-year limit on a previous assessment and 
argued that an assessment conducted before December 17, 2002 should be 
allowed as a baseline if it substantially meets the requirements of the 
rule and referenced standards. Dominion concurred with El Paso and 
added that the proposed rule penalizes operators for using prior 
assessments because it requires an operator to reassess immediately or 
within the next 2 years. Instead, Dominion suggested that the 
reassessment interval of seven years should start after the baseline 
assessment information is realigned and analyzed based on the 
operator's current program. INGAA took exception to the proposed 1997 
cutoff date and argued that RSPA/OPS was judging the applicability of 
earlier assessment technology without providing technical rationale. 
INGAA commented that RSPA/OPS should allow operators to use prior 
assessment data to encourage them to use the performance-based option.
    Response: Commenters are correct that the date listed for prior 
assessments was incorrect and should have been listed as December 17, 
1997 in the NPRM. However, that date is no longer relevant because the 
final rule has been revised to allow an assessment conducted any time 
prior to the date the Pipeline Safety Improvement Act was signed into 
law, December 17, 2002, as a baseline assessment if the prior 
assessment satisfies the requirements of Subpart O. There is no longer 
a five-year cut-off date for prior assessments.
    The final rule also allows prior assessments as part of the 
qualification basis for the performance-based option. For this option, 
an operator must demonstrate that the prior assessments effectively 
addressed the identified threats to the covered segment. Although these 
assessments may not meet all the requirements for a baseline, because 
the performance-based option sets additional and more stringent 
requirements, RSPA/OPS believes it could allow some flexibility in 
relying on prior assessments.
    RSPA/OPS has clarified the language concerning the time period for 
conducting the baseline assessment. The final rule no longer requires 
the baseline period to depend on the assessment technique used. The 
period is now the same, no matter the assessment method. Furthermore, 
as discussed earlier in this document, RSPA/OPS has eliminated the 
concept of Moderate Risk Areas. An operator must complete the baseline 
assessment of all covered segments by December 17, 2012, and assess at 
least 50% of the covered segments, beginning with the highest risk 
segments, by December 17, 2007. Consistent with the advisory 
committee's recommendation, we have revised the final rule to require 
that the first reassessment for a pipeline segment on which a prior 
assessment is credited as baseline must occur by December 17, 2009, 
seven years after enactment of the Pipeline Safety Improvement Act of 
2002.
    Any new pipeline that is installed in a high consequence area would 
be subject to the requirements of the rule. The final rule has been 
revised to require that newly-installed pipeline be included in the 
integrity management plan, and that the baseline assessments on any 
high consequence area segment be completed within ten years of 
installation. The rule provides that the installation pressure test, 
conducted in accordance with subpart J of part 192, would satisfy the 
requirements of a baseline assessment. Intervals for reassessment would 
be measured from the date of the baseline assessment, as for any other 
covered pipeline segment.
    RSPA/OPS has not specified in the rule what constitutes completion 
of an assessment on a covered segment, and therefore the date from 
which future assessment requirements toll. Such details were not 
included in the integrity management rule for hazardous liquid 
pipelines, but rather were addressed through additional guidance for 
implementing the rule. That guidance specifies that the end of field 
activities, e.g., completion of the final

[[Page 69791]]

tool run or completion of a hydrostatic test, is considered the end of 
an assessment. RSPA/OPS will issue similar guidance for this rule.
    Pressure Testing. We received comments on the proposal to allow 
pressure testing as an assessment method and that to address 
manufacturing and construction defects, a pressure test be conducted at 
least once in the life of the segment.
    NTSB noted that although defining HCAs can help to set priorities, 
risk management programs should ensure that pipelines are appropriately 
tested at all locations where there is public exposure and cited 
Carlsbad as an example. Advanced Technology Corporation asserted that 
there are other fracture mechanics assessment methods which would be 
preferable to pressure testing, which can cause crack growth.
    The majority of comments centered on the proposal to pressure test 
all segments once in the life of the pipeline. INGAA asserted, with 
numerous commenters echoing INGAA's comments, that experience has shown 
manufacturing and construction threats to be stable unless activated 
through a change in operations or the environment. The Association of 
Texas Intrastate Natural Gas Pipelines commented that once-in-a-
lifetime pressure testing should be eliminated and that testing 
conducted upon installation (post 1971) or based upon historical 
operation, provides adequate evidence of safety. Several commenters, 
including INGAA, suggested that the rule should be aligned with ASME/
ANSI B31.8S.
    Response: Pressure testing has long been considered the definitive 
method of testing pipeline integrity. RSPA/OPS has received no 
information that would challenge this historical practice, and pressure 
testing remains an acceptable assessment method in the final rule. 
RSPA/OPS has been convinced by the public comments, including 
discussions at the public meetings, that it is not necessary to require 
a once-in-a-lifetime pressure test to address the threat of material 
and construction defects. Historical safe operation, which in many 
cases involves several decades, provides confidence that latent defects 
will not result in pipeline failure as long as operating conditions 
remain unchanged. The final rule requires that an assessment be 
performed if operating pressure is increased above the historic level 
or if operating conditions change in a manner that would promote cyclic 
fatigue.
    Direct Assessment. There were numerous comments about the proposed 
requirements for using Direct Assessment (DA). In the proposed rule, 
direct assessment was allowed to address the threats of external 
corrosion, internal corrosion or stress corrosion cracking, and then 
only if certain preconditions were met. The proposed assessment 
intervals using this method were shorter than the ones proposed using 
the other assessment methods.
    In the NPRM, RSPA/OPS also requested comments on:
    [sbull] Whether it should allow an operator using Direct Assessment 
on a pipeline operating at less than 30% SMYS a maximum ten-year 
reassessment interval regardless of whether the operator excavates and 
remediates all anomalies on that pipeline, or at least remediates the 
highest risk anomalies. (68 FR 4278, 4281)
    [sbull] Whether the benefits of the proposed requirements for 
External Corrosion Direct Assessment, which were more extensive than 
the NACE Recommended Practices under development, were worth the cost. 
(68 FR 4278, 4282)
    Several commenters expressed serious concerns. Carol Parker 
commented that the method needs further study before being approved and 
Cook Inlet Keeper maintained that more stringent criteria are needed as 
compared to other assessment methods. Accufacts supported the proposed 
shorter assessment period for DA because it is a developing and 
unproven technology and further asserted that the related ICDA 
approaches are seriously deficient.
    In contrast, at least 125 comments, primarily from the pipeline 
industry, supported the use of Direct Assessment. For example, 
Northeast Gas Association supported using DA in the integrity 
management process because its research had showed that DA has a high 
degree of reliability. Numerous commenters asked that we incorporate 
the new NACE DA standard into the rule rather than duplicate the 
requirements. Most of the same commenters argued that DA should be 
considered equal to inline inspections and hydrostatic tests as an 
assessment method. Laclede Gas, along with other operators, asserted 
that DA is the only practical option for many local distribution 
companies and is better than inline inspection at finding coating 
damage that has not yet resulted in corrosion with wall loss. Other 
commenters maintained that DA should be explicitly identified as a 
technique for detecting potential third-party damage, and that the 
proposed treatment of DA is so prescriptive as to effectively eliminate 
it as an option.
    Commenters, including Southwest Gas, Paiute, Peoples Energy, PG&E, 
Kansas Gas Service, and Puget Sound commented that the proposed 
additional requirements were unnecessary, and were not beneficial. More 
than 20 commenters recommended incorporating by reference the NACE DA 
standard.
    Nine commenters agreed with the proposal to allow low-stress 
pipelines a ten-year reassessment interval. Over 30 commenters 
maintained that DA should be allowed the same schedules as those for 
inline inspections and hydrostatic tests. Other commenters, such as 
Sempra and the Iowa Utilities Board, supported less stringent rules for 
pipelines operating below 30% SMYS because of the lesser hazard posed 
by failure of such pipelines.
    Response: The process of Direct Assessment for evaluating the 
integrity of pipelines is new. Therefore, the proposed rule included 
restrictions on use of DA, including shorter baseline and reassessment 
intervals, because of concerns about the efficacy of the process. The 
NACE DA standard was still being developed when the proposed rule was 
issued.
    Although the process is new, the techniques involved in DA are not 
new. There are no new and untested technologies involved. Pipeline 
operators have used indirect examination tools in DA for many years, 
and there is a wealth of experience. Although exposing a pipeline for 
direct observation and evaluation of potential problems is the most 
reliable means of understanding pipeline condition, it is not practical 
to excavate and examine entire pipelines. The DA process is a method 
that involves structured use of the time-tested indirect examination 
tools, and integration of the information gained from use of those 
tools with other information about the pipeline, to determine where it 
is necessary to excavate and examine the pipe.
    A group of operators coordinated by Battelle and Gas Technology 
Institute, and co-funded by RSPA/OPS, conducted and documented 
additional research and validation of direct assessment after the 
proposed rule was published. RSPA/OPS personnel reviewed the results of 
this research, recognized the importance of careful inspections to 
ensure effective application of direct assessment, and recommended 
focused training of RSPA/OPS inspectors in the characteristics of an 
effective DA program. In addition, RSPA/OPS has included qualification 
requirements in the final rule for individuals that carry

[[Page 69792]]

out DA for those that interpret the results.
    Early results from the research have underlined the importance of 
operator vigilance in applying DA and of continuous incorporation of 
lessons learned in implementation procedures. The results of this 
research were discussed at the public meetings held during the comment 
period. These efforts have significantly improved RSPA/OPS's confidence 
in this method for assessing pipelines. RSPA/OPS has additionally been 
persuaded that many distribution companies operating transmission 
pipelines will need to rely heavily on this method. These companies' 
transmission pipelines are closely integrated with their distribution 
systems, are generally not amenable to inline inspection, and are often 
impractical to remove from service for pressure testing. Most also 
operate at low pressures, presenting relatively smaller risks than 
other transmission pipelines. Placing more restrictive requirements on 
use of DA would increase the burden, and costs, for operators of these 
low-risk pipelines without commensurate benefits.
    For all of these reasons, RSPA/OPS has concluded that it is 
unnecessary to place significant restrictions on the use of direct 
assessment. The final rule has been revised to make the required 
baseline and reassessment periods the same for DA as for other 
assessment methods. Conditions on the use of DA as a primary assessment 
method have been eliminated. These changes have rendered moot the 
question of whether a ten-year reassessment interval should be allowed 
for low-pressure pipelines even if all anomalies are not excavated.
    In the proposed section on using direct assessment to address 
external corrosion, we had drawn from a draft of the NACE standard on 
external corrosion that was close to completion. Since the proposed 
rule was published, NACE issued its recommended practice on external 
corrosion direct assessment (NACE Recommended Practice RP-0502-2002). 
RSPA/OPS has reviewed the recommended practice and concluded it has all 
the necessary requirements and safeguards to ensure the efficacy of the 
process.
    The NACE ECDA recommended practice (RP) has been incorporated into 
the final rule in the section addressing requirements for external 
corrosion direct assessment. The existence of NACE RP has allowed us to 
eliminate constraints on use of DA that were the subject of the 
questions in the preamble. Incorporating the standard is responsive to 
public comments, contributes to simplifying the rule, and is consistent 
with our overall practice of referencing consensus standards where they 
are available and meet regulatory needs. In addition, the rule 
specifies requirements beyond those in the NACE RP. Requirements in the 
rule that go beyond the NACE recommended practice address documentation 
criteria used in making decisions in implementing direct assessment. 
This documentation is needed to support oversight by RSPA/OPS and state 
pipeline safety authorities.
    NACE has not completed development of recommended practices for 
internal corrosion and stress corrosion cracking. The final rule 
references requirements in ASME/ANSI B31.8S applicable to these methods 
and includes additional requirements. RSPA/OPS will consider 
incorporating NACE standards for these techniques when those standards 
have been completed.
    Confirmatory Direct Assessment (CDA). The NPRM proposed allowing an 
operator to use Confirmatory Direct Assessment (CDA) as an assessment 
method at seven-year intervals if the operator established a longer 
reassessment interval using one of the other assessment methods. CDA is 
a more focused application of DA to address known threats in a pipeline 
segment.
    Industry generally embraced the concept of CDA. Dominion 
recommended allowing CDA as the first reassessment following a baseline 
assessment conducted after December 17, 2002. Houston Pipeline 
maintained that CDA should also be available for use on all pipelines 
previously assessed, not just those assessed using pressure testing or 
inline inspection. Sempra supported the use of CDA and suggested 
utilizing Section 5.10 of NACE RP0502 to determine the number and 
locations of excavations and direct examinations to be made if ECDA was 
used for the previous assessment.
    Although Northeast Gas Association supported the CDA concept, it 
suggested basing the CDA process on a technical industry standard, and 
streamlining the process so that only one dig in each segment is 
required as per the NACE standard instead of the proposed two digs. 
Peoples North Shore Gas stated that the proposed process only provides 
minimal relief as compared to full DA, echoed the need for 
streamlining, and provided several streamlining suggestions.
    Opposing the use of CDA, Cook Inlet Keeper maintained that CDA is 
not as effective as internal inspection or pressure testing. Cook Inlet 
suggested OPS compare the results for pipelines using CDA for 
reassessment to the results for pipelines using internal inspection or 
pressure testing for reassessment, and should CDA prove less effective 
than the latter two methods, reevaluate allowing its use.
    Response: CDA is a more focused version of Direct Assessment. The 
additional research and validation conducted in a project managed by 
the Gas Technology Institute, carried out by several operators working 
with Battelle, and funded by RSPA/OPS and the industry has increased 
RSPA/OPS's confidence in DA (as described above), as well as our 
confidence in CDA. The research had overview and partial funding by 
RSPA/OPS. It included comparison of results from various above-ground 
assessment tools with internal inspection runs completed on the same 
segments. The results are compelling enough to allow RSPA/OPS to 
support use of the technology under very careful oversight and with the 
assumption of continuing development and validation. The final rule 
requires that the baseline assessment on all covered segments must be 
by internal inspection, pressure testing, Direct Assessment, or other 
equivalent technology (with prior notice to RSPA/OPS) and that the 
reassessment must be by one of these methods at intervals specified in 
the rule and in ASME/ANSI B31.8S. CDA is an interim assessment 
technique designed for use when the reassessment interval by one of 
these methods exceeds seven years.
    The rule provides that CDA for external corrosion can be conducted 
using only one indirect measurement tool, rather than two complementary 
tools as required for Direct Assessment. The rule also provides for a 
more limited number of excavations, requiring excavation of only one 
scheduled indication in each ECDA region. Any ``immediate indications'' 
that are identified must also be excavated. The final rule also 
provides that additional assessment, using one of the other methods, 
must be performed if the CDA results do not confirm the integrity of 
the pipeline.
    Internal Corrosion Direct Assessment (ICDA). The NPRM proposed 
requirements for the use of Direct Assessment to address internal 
corrosion in a pipeline segment.
    Numerous commenters noted problems with the proposed ICDA language 
used in some of the requirements. Suggestions included: Rewording to 
clarify that internal corrosion can result from more than upset 
conditions, deleting references to chlorides, replacing ``moisture'' 
with ``electrolytes,'' replacing ``MIC'' with

[[Page 69793]]

``microorganisms,'' allowing the use of other measurement techniques 
that may be developed, referencing Graph E.III.1 when it is not a 
complete flow model, and replacing the word fluids with liquids, 
because gas is also a fluid.
    Both Paiute Pipeline and Southwest Gas asserted that ASME/ANSI 
B31.8S should be exclusively referenced rather than writing a procedure 
for ICDA within Part 192. The Northeast Gas Association questioned the 
need to excavate additional locations if, upon excavation of the first 
location most likely to corrode, no internal corrosion was found.
    NTSB commented that its investigation of the Carlsbad pipeline 
accident revealed areas where cleaning pigs had not been used that were 
likely locations for internal corrosion. NTSB suggested that RSPA/OPS 
highlight the increased corrosion potential of pipeline sections not 
subject to the periodic use of cleaning pigs.
    Response: NACE is developing recommended practices for ICDA, but 
none has yet been finalized. Discussion of ICDA in ASME/ANSI B31.8S is 
limited, but the final rule does reference the requirements in Appendix 
B2 of that standard. The final rule includes basic requirements 
consistent with the recommended practices now under development. These 
recommended practices, when completed, will provide additional guidance 
for implementing these requirements. The requirements provide for a 
minimum of two excavations in each ICDA region. RSPA/OPS has concluded 
that more than one excavation is needed, because predicting the 
locations at which internal corrosion could occur is not an exact 
science. There are different types of locations in which such corrosion 
can occur. Multiple excavations, and direct examination of potentially 
affected pipe, are necessary to ensure that internal corrosion will be 
found.
    RSPA/OPS has revised the language in the final rule to incorporate 
many of the suggested editorial comments. The final rule has also been 
revised to highlight the potential for increased corrosion of locations 
not subject to periodic use of cleaning pigs or in which cleaning pigs 
could deposit collected liquids.
    Reassessment Intervals: RSPA/OPS proposed that the reassessment 
interval begin when the baseline assessment of a covered segment was 
completed. This had been proposed consistent with the statutory 
requirement in 49 U.S.C. 60109(c)(3)(A) that an integrity management 
program include ``[a] baseline integrity assessment of each of the 
operator's facilities * * *.'' The length of the proposed reassessment 
intervals depended on the assessment method, although some form of 
reassessment would have to be done by the seventh year of the interval. 
If an operator used pressure testing or internal inspection, the 
maximum reassessment interval proposed was ten years for a pipeline 
operating at or above 50% SMYS and 15 years if operating below 50% 
SMYS. If an operator established the maximum interval, the notice 
proposed that a Confirmatory Direct Assessment would have to be done in 
the seventh and fourteenth years. If an operator used DA, the notice 
proposed a five-year interval if examining and remediating defects by 
sampling, or ten years if directly examining and remediating all 
anomalies. Again, if the ten-year interval were established, the notice 
proposed a CDA be conducted by the seventh year.
    In the NPRM, OPS requested comment on whether a rule should allow a 
maximum 20-year reassessment interval on pipelines operating at less 
than 30% SMYS, and reassessment by CDA method every seven years, 
without the need for reassessment by some other method, for pipelines 
operating below 20% SMYS (68 FR 4278, 4281). RSPA/OPS also sought 
comment on whether the rule should allow a maximum ten-year 
reassessment interval when DA is used on a pipeline operating at less 
than 30% SMYS.
    Cook Inlet Keeper supported the proposal to reassess a covered 
segment every seven years, rather than to begin the reassessment 
interval only after the baseline assessment of all covered segments in 
a transmission system was complete. Cook Inlet maintained the proposal 
was consistent with the Congressional intent to ensure covered segments 
are reassessed every seven years. Cook Inlet argued that without such 
an interpretation, a segment assessed early during the baseline 
assessment period might be assessed late during the reassessment 
period, resulting in over 16 years between assessments.
    Contrary to Cook Inlet's position, the vast majority of commenters 
argued that reassessment intervals should begin after the initial ten-
year baseline period, i.e., the reassessment interval should not begin 
until all segments have been initially assessed. INGAA requested that 
the rule clarify that the initiation of the first reassessment is not 
mandatory until completion of the baseline period for the system. INGAA 
asserted that without this change, operators will be conducting 
reassessments on their systems in HCAs at the same time as they are 
conducting baseline assessments, resulting in a potential for 
significant gas price spikes caused by outages on multiple pipeline 
systems occurring at the same time. INGAA claimed this would conflict 
with the intent of the legislation and preclude the ability to adjust 
priorities based on prior findings. Numerous commenters echoed INGAA's 
comments.
    Expanding on INGAA's position, NiSource asserted that without the 
change, outages in overlap years are likely to make it difficult to 
refill storage during summer months and lead to shortages and price 
spikes the following winters. Kansas Gas Service maintained that if the 
overlap were not eliminated, a bubble of demand for assessment services 
much greater than any other year would be created during the overlap 
years and would not be sustained beyond the bubble, resulting in 
operators facing difficulty obtaining services and experiencing supply 
interruptions. PSNC Energy also recommended eliminating the overlap 
because it would cause economic and labor-related hardships and lead to 
shortcomings from cutbacks in remaining baseline assessments. Northeast 
Gas Association and several other commenters noted that the 
reassessment intervals should be the same as identified in ASME/ANSI 
B31.8S.
    AGA proposed that the rule incorporate the maximum interval set for 
pipelines operating below 30% SMYS in the ASME/ANSI B31.8 standard, 
with interim preventive and mitigative measure being applied every 
seven years. Ten commenters, including Vectren, Dominion, and Northeast 
Gas Association, supported AGA's proposal that the rule allow a maximum 
20-year reassessment period for pipelines operating under 30% SMYS. 
Northeast Gas Association also recommended the 20-year interval also 
apply for Direct Assessment. Sempra, the Iowa Utilities Board, and 
other commenters supported less stringent requirements for pipelines 
operating below 30% SMYS because of the lesser hazard posed by failure 
of these low-stress pipelines.
    There were many comments on the proposed shorter reassessment 
intervals for operators using Direct Assessment. American Public Gas 
Association, American Gas Association, and several other commenters 
argued that DA reassessment intervals should be the same as for other 
methods. Williams Gas Pipeline maintained that having shorter DA 
intervals is not justified and Panhandle Eastern suggested that the 
reassessment intervals should be based on ASME/ANSI B31.8S. PG&E

[[Page 69794]]

supported a ten-year DA interval on pipelines operating at less than 
30% SMYS, which would be consistent with ASME/ANSI B31.8S. Sempra 
asserted that accelerating DA assessment schedules could result in 
assessment on some higher risk pipelines being deferred and suggested 
basing assessments on risk ranking of the various pipeline segments 
independent of the assessment method. The Association of Texas 
Intrastate Natural Gas Pipelines contended that Congress treated DA as 
equivalent to other methods of assessment and that RSPA cannot do 
differently. The Energy Association of Pennsylvania claimed the 
proposed seven-year interval is not consistent with the statute or 
Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use.
    In contrast, the New York Department of Public Service contended 
that extending the DA reassessment interval from five to ten years is 
unreasonable because external corrosion direct assessment is an 
immature process. New York asserted that although the Northeast Gas 
demonstration on the ECDA process showed that the process was reliable 
in identifying locations of current or potential corrosion activity, 
more experience is needed to characterize uncertainties and increase 
confidence that serious anomalies will be detected.
    With respect to the proposed CDA reassessment intervals, the State 
of New York asserted that CDA should not be considered a reliable 
assessment method and that full DA should be required every seven 
years. In contrast, Duke Energy opined that CDA should count as a valid 
reassessment and that a subsequent follow-up reassessment to CDA should 
not be scheduled for another seven years. Duke Energy recommended 
changing the rule to reflect that CDA is a valid reassessment technique 
on its own.
    Response: Congress required ``[a] baseline integrity assessment of 
each of the operator's facilities in areas identified pursuant to 
subsection (a)(1) [i.e., high consequence areas],'' and ``periodic 
reassessment of the facility, at a minimum of once every 7 years'' (49 
U.S.C. 60109).
    Industry commenters argued that this language can, and should, be 
read to require reassessments within seven years after the ten-year 
period in which baseline assessment of all covered segments had been 
completed. RSPA/OPS finds that the plain language of the statute 
precludes this interpretation. Industry suggests that the meaning of 
the word ``facility'' is key, and RSPA/OPS agrees. Elsewhere in the 
section requiring baseline assessments within 10 years of enactment, 
the statute states, ``At least 50 percent of such facilities shall be 
assessed not later than 5 years after such date of enactment. The 
operator shall prioritize such facilities for assessment based on all 
risk factors * * *'' (emphasis added). In contrast, the language 
requiring reassessment refers to periodic reassessment of the facility. 
Congress differentiated between individual pipeline segments and an 
operator's entire pipeline system. The statutory language is clear that 
an assessment of each covered segment is required at least every seven 
years.
    RSPA/OPS acknowledges that the requirements of the final rule will 
require that some reassessments be conducted before all baseline 
assessments have been completed. The rule has been written, however, in 
a manner intended to minimize the impact of this overlap to the extent 
practicable.
    The rule allows different methods for reassessment, and the maximum 
reassessment interval depends on the method used and the operating 
pressure of the pipeline. However, the reassessment required at seven-
year interval, the interval required by law, can be by Confirmatory 
Direct Assessment. CDA provides for much less potential disruption of 
pipeline operations than other assessment methods. No shut-down or 
curtailment of operation is needed to perform the indirect surveys that 
are a part of this method. Operators will likely reduce pressure when 
conducting excavations to protect personnel involved in that work, but 
the number of excavations required for CDA is less than for DA.
    Reassessment intervals for DA have been revised to be the same as 
those required for other assessment methods. This reduces the amount of 
pipeline that must be assessed each year when compared to the five-year 
reassessment requirement in the proposed rule.
    For pipelines operating below 30% SMYS, the final rule provides 
that the seven-year reassessment requirement can be met by a low-stress 
reassessment that includes indirect examinations, leak surveys, and 
other measures. The requirements for low-stress pipelines are discussed 
in item 7 of Comments to NPRM. This provision recognizes the relatively 
low risk posed by these pipelines and the likelihood that failures will 
result in leakage rather than rupture. Operators who implement this 
low-stress reassessment option also have the option of performing CDA. 
Reassessment for these low-pressure pipelines by the other methods 
allowed by the rule (i.e., pressure test, internal inspection, direct 
assessment) are required only every 20 years, the maximum interval 
allowed by ASME/ANSI B31.8S.
    ERW Pipe. Several comments concerned ERW pipe. The Gas Piping 
Technology Committee (GPTC) commented that the only way to assess seam 
issues is to conduct both an internal inspection and a pressure test, 
but such a requirement would not be practical. GPTC further commented 
that there are economic and technical barriers related to both 
Transverse Flux Inspection (TFI) and Ultrasonic tools. GPTC suggested 
the rule require that if an operator selects one of the multiple 
possible methods for assessment, it must consider the other method for 
reassessment. Sempra maintained the language on ERW pipe is unclear and 
that assessment should only be performed when a pipeline is subject to 
internal corrosion or when operating conditions could result in 
propagation of seam imperfections by fatigue.
    Response: If a covered pipeline segment contains low frequency 
electric resistance welded pipe (ERW) or lap welded pipe with a history 
of seam failure, an operator is required to select an assessment 
technology or technologies with a proven application capable of 
assessing seam integrity and of detecting seam corrosion anomalies. The 
operator is required to prioritize the covered segment as a high risk 
segment in its data integration and risk evaluation model.
    Training. Duke Energy argued that the appropriate place for the 
training requirements is under the existing operator qualification 
requirements of Subpart N and not within the integrity management 
requirements. Oleska and Associates contended that the proposed 
training requirements for supervisors are too broad and that 
understanding should be commensurate with job responsibilities and 
relationship to the program.
    Response: It is critical that personnel involved in integrity 
management programs and in conducting assessments have the appropriate 
training and qualifications for their functions. These functions are 
not, generally, within the scope of those covered by the Operator 
Qualification rule, because they are not tasks performed ``on the 
pipeline.'' In the final rule, RSPA/OPS has clarified the requirements 
for training, but continues to believe they are a necessary part of the 
rule.
    Other comments about program requirements. We received a number of 
miscellaneous comments on some of the

[[Page 69795]]

proposed integrity management program requirements. Cook Inlet Keeper 
requested that OPS review its database to ascertain whether there are 
additional threats to pipeline integrity, such as human error, 
maintenance problems, and valve and patch failures.
    Peoples Energy opined that the proposal to consider cyclic loading 
is specious because it requires operators to assume ``deep dents'' are 
present and further to determine if the loading conditions will lead to 
failure of the assumed ``deep dents.''
    Advanced Technology Corporation suggested redefining ``toughness'' 
as ``fracture toughness'' for older pipe materials to calculate the 
``critical defect size'' and to ensure the proper use of relevant 
information.
    Response: A systematic search of recorded incidents to identify 
threats to pipelines was conducted while developing the standard on 
integrity management, ASME/ANSI B31.8S. The rule is structured around 
evaluating susceptibility to these threats and protecting against them. 
RSPA/OPS believes that the best way to address threats associated with 
human errors is through training and qualification, since failures from 
this cause usually occur immediately.
    With respect to cyclic loading, it is important that a realistic 
analysis of the condition be conducted to ascertain the susceptibility 
of pipelines to failure from this cause. Such analyses require the 
postulation of some flaw, because the effect of cyclic loading is to 
propagate existing flaws. Flawless pipe can generally withstand 
significant cyclic loading, but little pipe is completely without 
flaws. The final rule requires an operator to use the results from the 
evaluation together with the criteria used to evaluate the significance 
of this threat to the covered segment to prioritize the next integrity 
assessment.
    In the final rule, we have substituted the term ``fracture 
toughness'' for ``toughness.''
5. Review, Notification and Enforcement Processes
    There were several comments related to review, approval, and 
enforcement processes but the majority related to the use of and 
practicality of waivers. RSPA/OPS had proposed to allow a waiver of a 
reassessment interval greater than seven years in two limited 
instances: Lack of internal inspection tools and to maintain local 
product supply. The statute limits a waiver to these two instances.
    The proposal included prior notification requirements to OPS in 
several instances: When using other technology as an assessment method 
(180 days), When making a significant change to the integrity 
management program (30 days), and when seeking a longer reassessment 
period (180 days before the end of the required period).
    Sempra commented that the potential impact on customers is greater 
than perceived primarily because of the impact to numerous large 
customers served by a single source pipeline, and therefore the need 
for waivers may have been greatly underestimated. Panhandle Eastern 
asserted that waiting 180 days for a decision on a waiver is excessive. 
The Washington Utilities and Transportation Commission suggested that 
we include provisions that would require RSPA/OPS to approve or 
disapprove of an operator's request for waiver.
    Enron was concerned about the proposed program change requirements 
and asserted that the terms ``significantly'' and ``substantially'' are 
vague and subject to varying interpretations. Enron further argued that 
requiring separate, subjectively determined notifications is not 
productive or useful when changes could be effectively reviewed during 
regular pipeline program reviews.
    Several commenters, including Advanced Technology Corporation, 
suggested that RSPA/OPS better define the process by which new 
technologies are approved. Both PECO and El Paso objected to the 180-
day notification prior to the use of new technology and El Paso 
suggested that the notification period be reduced to 90 days, which 
would be consistent with Sec.  195.452. El Paso also suggested that 
provision be made for the ongoing use of other technology via a single 
notification.
    Sempra encouraged RSPA/OPS to address the coordination of 
environmental review and the permit process for pipeline repairs and 
for retrofitting and inspection of pipelines per Section 16 of the 
Pipeline Safety Improvement Act of 2002.
    Response: RSPA/OPS acknowledges that the number of waivers likely 
to be sought by operators is not known at this time. Nevertheless, 49 
U.S.C. 60109 requires that an assessment be performed on a pipeline 
segment in a high consequence area at seven-year intervals and further 
provides that operators may seek waivers only under two circumstances. 
The waiver requirements in this rule follow the statute. Because of the 
statutory limitations, RSPA/OPS cannot make other changes in 
anticipation of a large number of waivers possibly being submitted many 
years hence. RSPA/OPS believes that careful planning can help avoid the 
need for waivers. Careful planning also will identify the need for 
waivers in sufficient time to allow operators and RSPA/OPS to conduct 
careful reviews. RSPA/OPS is working on expediting the waiver process 
to prevent potential supply shortfalls. RSPA/OPS expects that a 
requirement to apply for a waiver 180 days before the end of the 
required reassessment interval is reasonable, except when local product 
supply issues may make that period impractical. In such an instance, an 
operator would need to apply for the waiver as soon as the need for the 
waiver becomes known. The waiver process is governed by 49 U.S.C. 
60118, the Federal pipeline safety law. Currently, a waiver must be 
published for public comment. Therefore, 180 days is a reasonable 
period to allow for publication in the Federal Register and to address 
public comments on the a proposed waiver.
    To address the TPSSC's recommendation we have revised the language 
in the final rule to include the exact language of the statute 
pertaining to waivers. Therefore, a waiver may be sought to maintain 
local product supply or because of unavailability of internal 
inspection devices. In either case, RSPA/OPS must determine that a 
waiver would not be inconsistent with pipeline safety.
    The Pipeline Safety Improvement Act of 2002 also requires that 
operators notify RSPA/OPS when they make changes to their integrity 
management programs. RSPA/OPS cannot eliminate this requirement from 
the rule. The requirement has been conditioned to require notification 
only of changes that may substantially affect the program's 
implementation or may significantly modify the program or schedule for 
carrying out the program elements. These qualifiers are intended to 
preclude notifications for minor, even editorial, changes.
    We have revised this requirement, however, to require an operator 
to notify, in addition to OPS, a State or local pipeline safety 
authority when a covered segment is located in a State where OPS has an 
interstate agent agreement, and a State or local pipeline safety 
authority that regulates a covered pipeline segment within that State. 
These changes were made to address comments from advisory committee 
members and State pipeline safety authorities.
    RSPA/OPS continues to believe that 180-day notice before an 
operator uses ``other technology'' is a reasonable notification period. 
There are reasons why the corresponding period in the rule for 
hazardous liquid pipelines is 90

[[Page 69796]]

days. The reassessment period for hazardous liquid pipelines is five 
years, a period about 70 percent of the shortest reassessment period in 
this rule. Therefore, planning decisions must be made for liquid 
reassessments on a shorter time frame. In addition, the ``other 
technology'' most likely to be used by hazardous liquid operators is 
direct assessment, an assessment method specifically allowed in the gas 
integrity management rule but not in the liquid rule. Because there is 
now an industry standard and more information about the process is 
known, the review of the notification is likely to be shorter. ``Other 
technologies'' that gas transmission pipeline operators may use are 
expected to involve methods and techniques that are more developmental 
and about which less information is known. This will require that RSPA/
OPS take more time in reviewing these notifications before the ``other 
technology'' is implemented.
    Section 16 of the Pipeline Safety Improvement Act of 2002 (49 
U.S.C. 60133) requires the establishment of an interagency coordinating 
committee and that this committee take actions to help ensure that 
pipeline operators will be able to obtain permits when required to 
perform required repairs. The interagency committee has been 
established. RSPA/OPS is participating on the committee. Those actions 
are related to, but independent of this rule, and will not be described 
here in detail. It is important to note, however, that the rule 
provides a mechanism for operators to address situations in which 
repairs cannot be made due to inability to obtain permits. The rule 
provides that operators can reduce operating pressure or take other 
action to ensure the integrity of the pipeline. If neither can be done, 
the operator is required to notify RSPA/OPS. RSPA/OPS expects that 
operators will exercise due diligence in seeking permits for repairs.
6. Consensus Standard on Pipeline Integrity
    The Standards-Developing Organizations Coordinating Council (SDOCC) 
urged RSPA/OPS to incorporate industry standards by reference in their 
entirety into the regulations. The Council asserted this will help 
avoid misinterpretations that can result from parts of standards being 
used out of context, or from text taken from standards being used in 
regulations without reference to the source. Similarly, both New Jersey 
Natural Gas and Advanced Technology Corporation suggested that inline 
inspection consensus standards must both be developed and then 
supported by OPS.
    Many commenters wrote to request that OPS utilize performance-based 
options that are both measurable and achievable, and suggested using 
the ASME/ANSI B31.8S consensus standard to achieve those ends. 
Northeast Gas Association recommended that the rule refer to ASME/ANSI 
B31.8S for performance versus prescriptive requirements. El Paso went 
further and asserted that the proposed requirements for the 
performance-based option are not measurable or achievable and should be 
revised to allow the ASME/ANSI B31.8S standard to provide the structure 
and framework. Cook Inlet Keeper recommended that RSPA/OPS review the 
ASME/ANSI B31.8S standard to ensure that the standard is enforceable 
and where necessary provide clarification in the final rule.
    Response: The final rule incorporates ASME/ANSI B31.8S--2001, 
Managing System Integrity of Gas Pipelines, and uses that standard for 
many of the rule's requirements, including those for the performance-
based option. RSPA/OPS has reviewed ASME/ANSI B31.8S to ensure it is 
enforceable. The rule has been written to ensure that the requirements 
are enforceable.
7. Low-Stress Pipelines
    The proposed rule did not differentiate requirements for low-stress 
pipelines. However, as discussed in previous sections of this document, 
RSPA/OPS sought comment on less stringent requirements for these 
pipelines, particularly with respect to--
    [sbull] Whether to allow an operator using direct assessment on a 
pipeline operating at less than 30% SMYS a maximum ten-year 
reassessment interval regardless of whether the operator excavates and 
remediates all anomalies on that pipeline, or at least remediates the 
highest risk anomalies. (68 FR 4278, 4281)
    [sbull] Whether to allow a maximum 20-year reassessment interval on 
pipelines operating at less than 30% SMYS, and reassessment by 
confirmatory direct assessment method every seven years (without the 
need for reassessment by some other method) for pipelines operating 
below 20% SMYS. (68 FR 4278, 4281)
    Several commenters suggested that the assessment requirements 
proposed for low-stress pipelines (i.e., pipelines operating at below 
30 percent SMYS) were unnecessary and overly burdensome. Many industry 
commenters pointed out that low-stress pipelines tend to fail by 
leakage rather than by rupture and, therefore, pose considerably less 
risk than pipelines operating at higher stresses. The commenters 
proposed various alternatives, including use of the inspection 
intervals in ASME/ANSI B31.8S (which calls for inspections at 20-year 
intervals for low-stress pipelines), allowing use of confirmatory 
direct assessment for baseline assessments, implementation of 
preventive and mitigative measures in lieu of assessment requirements, 
and changing the definition of transmission pipeline to exclude 
pipelines operating at less than 20% SMYS. National Fuel contended that 
pipelines that operate at less than 20% SMYS cannot create high 
consequences and, therefore, the high consequence area definition 
should exclude such pipelines. National Fuel recommended that, if RSPA/
OPS must include these pipelines by statute, enhanced preventive and 
mitigative measures should be allowed for the baseline assessment and 
reassessment.
    AGA recommended that the intervals in ASME/ANSI B31.8S be used. AGA 
provided suggested preventive and mitigative measures for all pipeline 
in Class 3 and 4 areas and numerous commenters supported AGA's 
comments. AGA also proposed, at public meetings held during the comment 
period, that pipelines operating at less than 20% SMYS be subject to 
requirements for baseline assessments and for reassessment at the 
intervals specified in ASME/ANSI B31.8S. The AGA recommendations 
included electrical surveys, which would inspect for cathodic 
protection problems that would precede corrosion damage, and leak 
surveys, which would inspect for the failure mechanism most likely on 
low-stress pipelines, as a reassessment method suitable to meet the 
statutory seven-year requirement.
    AGA further proposed a set of preventive and mitigative measures as 
alternate assessment methods for reassessment of pipelines inside HCAs. 
The additional measures targeted external and internal corrosion and 
third-party damage. Other commenters supported this alternative, 
including TXU Gas, National Fuel, and the New York State Department of 
Public Service.
    The Iowa Utilities Board agreed that less stringent requirements 
should be applied to pipelines operating below 30% SMYS. New York 
Department of Public Service suggested that 20 years was too long an 
interval between assessments, and pointed out that although a low-
stress pipeline is likely to fail by leakage, these pipelines are 
located in highly populated areas.

[[Page 69797]]

    Response: Pipelines that operate at less than 20% SMYS are 
transmission pipelines if they meet the functional definition in Sec.  
192.3. The statute (49 U.S.C. 60109) does not except low-stress 
pipelines from the integrity management program requirements, including 
the requirement for reassessment at seven-year intervals. RSPA/OPS has 
revised the requirements, however, in recognition of the relatively low 
risk posed by pipelines operating at less than 30% SMYS. First, the 
rule allows two methods to define a high consequence area, so that an 
operator of a low-stress pipeline can rely on data it has already 
collected to identify the areas.
    Second, the rule allows an alternative method of reassessment that 
focuses on the type of risk posed by these low-stress pipelines. RSPA/
OPS agrees with AGA that these pipelines should be assessed initially 
and at the 20-year interval by the methods being used to assess higher 
stress pipelines, and has so required in the rule. During the 20-year 
interval, a low-stress line must be reassessed at seven year intervals 
by a low-stress reassessment, which is described below, or by 
confirmatory direct assessment. The rule incorporates confirmatory 
direct assessment (CDA) as a focused method of performing these interim 
assessments for pipelines operating at higher pressure. However, for 
low-stress pipelines, RSPA/OPS agrees that even CDA could be unduly 
burdensome. Therefore, the final rule adopts AGA's suggestion that 
electrical surveys are appropriate for conducting these interim low-
stress reassessments between the assessments performed by methods being 
used to assess higher stress pipelines.
    The rule allows operators of low-stress pipelines an option. They 
can perform CDA on seven-year intervals or they can conduct a low-
stress reassessment that focuses on the types of threats these 
pipelines experience. A low-stress reassessment includes an electrical 
survey at least every seven years. For cathodically unprotected 
pipeline or areas where electrical surveys are impractical, increased 
leak surveys are required at a rate twice the current requirement. The 
additional measures also include provisions to protect against internal 
corrosion and third-party damage. RSPA/OPS has concluded that these 
measures provide appropriate interim protection for low-pressure 
pipelines, where the failure mode is predominantly leakage instead of 
rupture.
    RSPA/OPS has also adopted AGA's suggestion that enhanced preventive 
and mitigative measures be required for low-stress pipelines located in 
Class 3 and 4 areas. These measures protect against third-party damage, 
the type of threat most likely to result in a significant failure on 
these pipelines.
8. Remedial Actions--Sec.  192.931 (Formerly Sec.  192.763(i))
    There were numerous comments about the proposed remediation 
requirements particularly with respect to the proposed time periods for 
discovery, pressure reduction and remediation, and the proposed repair 
criteria in general and for dents.
    The proposed requirements for scheduling remediation of anomalous 
conditions found during an assessment provided for immediate repair 
conditions, 180-day conditions, and conditions where remediation would 
take longer than 180 days. The 180-day conditions included certain 
dents. The proposed rule also referenced B31.8S as the basis for making 
repairs.
    Industry commenters generally supported INGAA's suggestion that the 
repair criteria should be based on the industry standards, ASME/ANSI 
B31.8 and B31.8S. INGAA further suggested that the proposed 180-day 
time frame for evaluation and remediation of certain conditions should 
be changed to one year. INGAA explained that the 180-day limit would 
require remediation during winter months when the demand for gas is 
high. One year would allow operators one complete operating cycle in 
which to complete the work. Industry commenters supported this 
suggestion. INGAA also submitted recommended rule language that allowed 
time frames of one-year, more than one-year and monitored conditions, 
i.e., conditions that would not have to be scheduled for remediation.
    INGAA, and other industry commenters such as El Paso and Panhandle 
Eastern, contended that the requirement to remediate dents should be 
reconsidered and should be revised to distinguish between bottom-side 
and top-side dents. These commenters explained that constrained dents 
are not a threat. Depressions or dents in the bottom of the pipe are 
constrained; dents on the top of the pipe that are relatively 
unconstrained. Commenters recommended that the distinction be made by 
specifying remediation for dents between the 8 and 4 positions and on 
monitoring dents that do not need to be remediated.
    The proposed remediation requirements provided that a pressure 
reduction could not exceed 365 days unless the operator took further 
remedial action to ensure the safety of the pipeline. Many commenters, 
including the Gas Piping Technology Committee and Nicor Gas, argued 
that there is no basis for the proposed 365-day limit on pressure 
reduction and that operators should be allowed to use long-term 
pressure reduction if it provides equal or better safety. Public 
Service Electric and Gas Company asserted that the 365-day limit is not 
supported by any data analysis or risk assessment and should be 
removed. El Paso argued that pressure reductions should not be based on 
the pressure at the time of discovery but based possibly on either the 
MAOP or the highest pressure in the last 30 days. Sempra suggested we 
use technical information from a Pipeline Research Council 
International report that stated a pressure reduction in these 
circumstances may be determined using the highest pressure survived by 
the flaw since the time that it occurred.
    The proposed discovery requirements were also a concern to many 
operators. The proposed rule provided that discovery occurs when an 
operator had adequate information about the condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline, and that discovery could occur no later than 180 days after 
conducting an integrity assessment unless the 180-day period is 
impracticable. Dominion contended the proposed language is confusing 
and suggested that discovery be tied to a time when the operator has 
adequate information concerning the conditions to determine that an 
indication requires a response as defined in ASME/ANSI B31.8S. INGAA 
and many other industry comments suggested that the proposed 180-day 
requirement associated with the discovery date be extended to one year 
to be consistent with ASME/ANSI B31.8S.
    Response: We have revised the remediation requirements in the final 
rule. The rule provides that an operator be able to demonstrate that 
the remediation of the condition will ensure that the condition is 
unlikely to pose a threat to the integrity of the pipeline until the 
next reassessment of the covered segment. We thought this language more 
definite than being able to demonstrate a remediation will ensure the 
condition does not pose a threat to the long-term integrity of the 
pipeline. The final rule continues to provide that discovery occurs 
when an operator has adequate information about the condition to 
determine that the condition presents a potential threat to the 
integrity of the pipeline. Adequate information to make this 
determination would include information that the condition is one 
included in ASME/

[[Page 69798]]

ANSI B31.8S as needing a response. The rule also continues to specify 
that this must occur within 180 days after conducting the assessment, 
unless the operator demonstrates the 180-day period is impracticable. 
This is the same period used for the corresponding requirement for 
hazardous liquid pipelines. RSPA/OPS considers that identified 
anomalies should be dealt with promptly, and that delaying the 
requirement for discovery to occur until one year after an assessment 
is not consistent with that need.
    The basis on which RSPA has accepted the recommendation to change 
the time allowed for evaluation and remediation of certain defects from 
180 days to one year is that gas pipelines typically do not operate 
with pressure fluctuations sufficient to cause cyclic fatigue. 
Therefore, the subject defects can be allowed to remain for up to one 
year. In addition, this position is consistent with provisions of ASME/
ANSI B31.8S.
    The remediation requirements associated with dents have been 
revised in response to the comments to distinguish between bottom-side 
and top-side dents. The rule now provides that dents greater than 6% of 
the pipe diameter in depth in the top two-thirds of the pipe (i.e., 8 
o'clock to 4 o'clock), or greater than 2% and affecting curvature at a 
weld, must be remediated in one year. The rule allows such dents to be 
treated as monitored conditions if an operator obtains information and 
performs engineering analyses to demonstrate that critical strain 
levels have not been exceeded. An operator must also monitor dents on 
the bottom-third of the pipeline. The rule now also differentiates 
between smooth and abrupt dents because abrupt dents need to be 
prioritized for evaluation before smooth dents.
    We have revised the requirement for pressure reduction. If an 
operator is unable to respond within the required time limits for 
certain conditions, the operator must temporarily reduce the operating 
pressure of the pipeline or take other action that ensures the safety 
of the covered segment. Thus, a pressure reduction is not automatic. If 
the operator reduces pressure, the reduction cannot exceed 365 days 
without an operator providing a technical justification that the 
continued pressure restriction will not jeopardize the integrity of the 
pipeline. The requirement that a pressure reduction cannot last more 
than 365 days without further action is identical to a requirement in 
the integrity management rule for hazardous liquid pipelines. The 
reduction provides an increased margin of safety in the interim, while 
repair can be planned and implemented.
9. Additional Preventive and Mitigative Measures, Including, Leak 
Detection Devices and Automatic Shut-Off and Remote Control Valves--
Sec.  192.933 (Formerly Sec.  192.763(j))
    We received a large number of comments on the proposed additional 
preventive and mitigative measures.
    INGAA asserted that excavation damage is the primary cause of 28% 
of reportable incidents and that the proposed rule focuses primarily on 
previously damaged pipe which is associated with only 4% of reportable 
incidents. INGAA proposed additional requirements be incorporated for 
the prevention of third-party damage and that the assessment for 
previously damaged pipe be integrated into the assessment processes for 
other failure causes. Dominion suggested eliminating the proposed 
requirement to conduct an internal inspection looking for third-party 
damage because it is ineffective. Equitable opposed pressure testing 
for third-party damage detection asserting there is no technical 
justification. These and many other commenters opposed the proposal to 
utilize an assessment tool to identify third-party damage. Commenters 
agreed that direct assessment is the number one tool for assessing 
third-party damage. Numerous commenters, including Enron and the 
Northeast Gas Association, argued that prevention is the best approach 
and urged RSPA/OPS to champion efforts to eliminate exemptions to the 
various state one-call programs.
    AGA proposed a set of additional preventive and mitigative measures 
as assessment methods for addressing external and internal corrosion 
and third-party damage for pipelines operating below 30% SMYS and not 
in HCAs but in Class 3 and 4 locations. Again, numerous commenters 
supported these additional preventive and mitigative measures including 
NiSource, Laclede Gas, and the Association of Texas Intrastate Natural 
Gas Pipelines.
    Several comments related to the proposal to install automatic shut-
off valves and remote control valves as potential risk mitigative 
measures. None of those commenters supported their use. PSE&G asserted 
there is no technical justification for their use and Enron asserted 
that it has been demonstrated that these valves provide no additional 
safety benefit. Panhandle Eastern referenced a Gas Research Institute 
Report which, according to Panhandle Eastern, concludes that the cost 
of installing the valves is not justified by the limited benefit.
    One company commented that its leak detection system would be 
effective on gas pipeline systems and asked that RSPA review the system 
for potential use on natural gas pipelines to better monitor leaks.
    Response: The final rule incorporates additional requirements to 
help prevent accidents caused by third-party damage, including 
requiring participation by pipeline operators in one-call systems. We 
have not included the proposed requirement to conduct assessments 
specifically to evaluate possible third-party damage.
    The rule also incorporates additional prevention and mitigation 
requirements for low-stress pipelines that are located in Class 3 and 4 
areas but not HCAs. This was not an issue in the proposed rule, because 
all Class 3 and 4 areas would have been defined as HCAs. The revised 
definition for HCAs included in the final rule will mean that some 
pipeline in populated areas (i.e., Class 3 and 4) will not be 
determined to be in HCAs. RSPA/OPS agrees with AGA that it is 
appropriate that additional measures be implemented in these populated 
areas to protect the pipeline. The final rule incorporates the 
provisions recommended by AGA.
    With respect to automatic and remotely-operated shut-off valves, 
RSPA/OPS acknowledges generic work, some sponsored by RSPA/OPS that 
concluded that installation of such valves is usually not cost-
beneficial. The conclusions of those studies were based, however, on 
generic, average conditions. It is possible that conditions particular 
to individual pipeline segments in HCAs may change this conclusion, 
making it appropriate to install or modify valves. The rule requires 
operators to make this determination and to install a valve if it would 
be an efficient means of adding protection to a high consequence area 
in the event of a gas release. RSPA/OPS does not expect that operators 
will perform detailed technical analyses that duplicate the work done 
in the generic studies. Instead, operators will use the generic work as 
a starting point and then evaluate whether the generic conclusions are 
applicable to their high consequence area pipeline segments. The 
results of this evaluation must be documented for review during RSPA/
OPS inspections.
    As for the leak detection system the commenter described, RSPA/OPS 
does not require that operators install particular safety systems, nor 
does it endorse them. Vendors who believe their systems will allow 
companies to

[[Page 69799]]

meet requirements of this rule in a cost-effective manner should 
approach pipeline operators directly.
10. Methods To Measure Program Effectiveness--Sec.  192.941 (Formerly 
Sec. Sec.  192.763(c)(5) and 192.763(l))
    Reporting requirements associated with the proposed rule generated 
a number of comments, most in opposition to the proposed requirements. 
Proposed requirements included an operator making accessible in real 
time the four overall performance measures and the additional 
performance measures, if trying to qualify for exceptional performance 
under the performance-based option.
    New Jersey Natural Gas Company and New York State Department of 
Public Service commented that a rule will need to clarify ``real 
time.'' Northeast Gas Association also requested a definition and 
clarification of what is meant by ``real time'' and suggested that we 
use the performance measures identified in Section 9.4 of ASME/ANSI 
B31.8S instead of those in the proposed rule.
    Many commenters, including Nicor Gas, Kern River, and Consumers 
Energy, opposed the use of ``real time'' accessibility to performance 
data and suggested alternatives ranging from quarterly to annually. El 
Paso suggested a web-based reporting system and PECO was concerned 
about security of database systems housing this data.
    Numerous commenters supported INGAA's proposal about how to make 
the collection of data on performance measures more efficient and 
reflective of the effectiveness of an integrity management program. 
INGAA proposed that real time mean on a quarterly basis for reporting 
the number of miles assessed and the number of repairs. In addition 
INGAA recommended that information fields be added to the Annual report 
form submitted by gas transmission operators to track and compare the 
number of leaks eliminated or repaired in HCAs with those not in HCAs.
    Response: RSPA/OPS has eliminated the requirement for operators to 
post performance measures in a manner that would allow regulators to 
access them electronically in real time. Instead, the general 
performance measures (which are those specified in Section 9.4 of ASME/
ANSI B31.8S) must be submitted to OPS semi-annually. This periodicity 
results from discussions at the public meetings held during the comment 
period and with the Technical Pipeline Safety Standards Committee, and 
is consistent with the recommendation adopted by the committee. RSPA/
OPS will compile this information and make it available electronically 
to other pipeline safety officials and to the public.
    Other suggestions by INGAA concerned forms that were not part of 
the rulemaking. We will consider these suggestions and if the forms 
should be revised to incorporate fields for the data.
11. Information for Local Officials and the Public
    The proposed rule did not propose that operators provide 
information to the public. The proposed rule proposed that an operator 
have a means to provide a copy of its integrity management program to a 
State with which OPS has an interstate agent agreement and a 
communications plan that included a process for addressing safety 
concerns raised by OPS or an interstate agent. These requirements were 
mandated by statute. The notice further proposed that the performance 
measures be provided in real time to state pipeline safety officials.
    At the advisory committee meeting, the Committee noted that State 
authorities need to be aware of these reports for intrastate pipelines, 
and for interstate pipelines in states in which the State acts as an 
interstate agent.
    Carol Parker suggested that a requirement should be included to 
notify people who frequent areas where pipelines are not inspected.
    Cook Inlet Keeper commented that the four overall performance 
measures that OPS proposed an operator maintain (i.e., the measures in 
Section 9.4 of ASME/ANSI B31.8S standard), should be made available to 
the public in a web-based analyzable format. In addition, Cook Inlet 
suggested providing other information such as the primary threats to 
covered segments, the assessment tools and their schedules, along with 
other non security-related data.
    Similarly, the Inline Inspection Association suggested that 
operators should be required to report to OPS certain information from 
their plans, including segments to be inspected, diameters, potential 
threats, and planned assessment methods. OPS should then make this 
information available to the public to allow the inline inspection 
industry to develop and procure the appropriate tools and train 
personnel to provide the needed services.
    Accufacts asserted that a rule should include ``Right-to-Know'' 
provisions, to include reporting specific information to RSPA/OPS such 
as mileage in HCAs and total mileage by Class area. Accufacts further 
commented that high consequence area information should be reported to 
state and local governmental agencies when requested.
    As previously discussed, both the Washington State Advisory 
Committee on Pipeline Safety and the Washington City and County 
Pipeline Safety Consortium suggested that operators work with local 
cities or municipalities to identify additional HCAs within their 
territories. They asserted that cities and municipalities have the best 
information on facilities and on growth trends for their areas which 
would be beneficial in identifying HCAs.
    The Iowa Utilities Board commented that the proposed rule appears 
to reserve all reporting and oversight for RSPA/OPS, with no 
recognition of the role played by the states. Iowa opined that the 
proposed rule recognizes only interstate pipelines, when by including 
all gas transmission pipelines within the scope of the rule, large 
numbers of transmission pipelines belonging to intrastate operators 
will be affected. Iowa suggested that the rule recognize the 
traditional role of state pipeline safety programs and their oversight 
of intrastate pipeline operators.
    Industry commenters had many concerns about the security of 
providing information to the public. Consolidated Edison requested that 
OPS clarify how security will be maintained if the detailed information 
submitted by operators is made available to the public. Duke Energy 
contended that implementation of the proposed integrity management 
regulations have implications for national security that have not been 
considered or addressed. Duke Energy noted that at the public meeting 
in Houston, RSPA/OPS had agreed to look into how to control access to 
this information.
    Response: RSPA/OPS agrees that information concerning gas 
transmission pipeline integrity management should be made available to 
the public. At the same time, RSPA/OPS agrees that there are issues, 
including security concerns, regarding how much information is 
provided. RSPA/OPS recognizes that not every state has laws to protect 
the release of proprietary or sensitive information. In the final rule, 
RSPA/OPS has tried to balance the need to know against the need to keep 
certain critical information secure. RSPA/OPS believes that the four 
performance measures an operator is required to include in its program 
(as specified in Section 9.4 of ASME/ANSI B31.8S) provide the 
appropriate level of information for members of the public to see how 
pipeline operators are doing in their integrity management program. The 
rule provides that operators submit this information to OPS semi-
annually.

[[Page 69800]]

OPS will assemble this information and will make it available, on the 
internet, to the public and to state safety agencies.
    RSPA/OPS does not consider it appropriate to collect additional 
information relevant to integrity management for public dissemination. 
RSPA/OPS will implement an inspection program to evaluate operator 
implementation of this rule. Those inspections will ensure that 
operators have proper commitment to integrity management, that they are 
scheduling and conducting their assessments as required, that they are 
using appropriate assessment methods, and that they are adequately 
integrating data. Regulators will take enforcement action when 
appropriate, and records of such enforcement will be available to the 
public as they are now.
    The pipeline safety statute (49 U.S.C. 60109) requires that an 
operator provide a copy of its risk assessment and integrity management 
program to an interstate agent. Although we recognize an operator's 
security concerns with providing this information, we must include the 
requirement with respect to interstate agents. We recognize the role of 
State pipeline safety authorities with respect to intrastate 
transmission pipeline. But because of the comments and concerns about 
security and protecting this information, we do not want to require 
that operators also provide the States this information on intrastate 
pipelines. Each State's laws vary and a State may not be able to 
protect this information from public release. We will look into a means 
of how RSPA/OPS can share this information with a state pipeline safety 
authority while ensuring the information is protected. However, the 
rule does provide that when a State regulates a covered pipeline 
segment within that State, an operator provide the State notice about 
changes made to the operator's integrity management program and when 
making a repair, the operator cannot meet the required schedule for 
repair and cannot temporarily reduce pressure or take other action to 
ensure the integrity of the pipeline.
    As discussed above, RSPA/OPS agrees that local safety officials are 
key elements in the identification of HCAs, and has revised the final 
rule to so specify. OPS expects that the regular interaction between 
pipeline operators and those officials will also serve to increase 
local officials' level of knowledge regarding the operators' integrity 
management efforts.
    It would be inappropriate to include requirements in a safety rule 
simply to elicit information that a vendor can use to develop its 
business.
12. Cost-Benefit Analysis
    In the preamble of the proposed rule RSPA/OPS stated that it has 
never received comments from small gas transmission operators 
concerning the burdens of its regulations and that RSPA/OPS believed 
that the costs of its proposal would be proportionate to the amount of 
mileage the pipeline company operates. RSPA/OPS requested public input 
on any potential undue impact that this proposal would have on any 
small entities. (68 FR 4278, 4313.)
    Very few commenters specifically addressed this question. Vectren 
stated there would be significant undue impacts associated with this 
new rule and provided estimated information relative to Vectren through 
2013. Vectren's estimates showed in excess of 11% per year reductions 
in annual income through 2012. Similarly, the Iowa Utilities Board 
commented that burdens on small pipelines and operators should be 
minimized.
    Carol Parker suggested that RSPA/OPS use the impact on the 
California economy in dollars to support the cost-benefit analysis of 
required inspection programs. Taking a somewhat opposing view, the Iowa 
Utilities Board asserted that the proposed requirements for pressure 
testing do not adequately recognize the tremendous social and economic 
consequences of interrupting service from the majority of intrastate 
pipelines. The Association of Intrastate Natural Gas Pipelines 
contended that the supply interruptions that may be caused by the rule 
have been understated, particularly during the period of any overlap. 
Questar asserted that RSPA/OPS has understated the true costs and this 
will be problematic if rate regulators adopt the RSPA/OPS analysis as a 
benchmark. New Jersey Natural Gas Company was concerned that the cost 
estimates for retrofitting are not accurate. INGAA provided a series of 
alternatives to the proposed regulations and provided their own 
estimates of savings associated with those changes.
    The Energy Association of Pennsylvania estimated that over 
$2,341,000,000 will be saved if the baseline overlap is eliminated.
    AGA estimated that over $1,100,000,000 will be saved if preventive 
and mitigative measures are used to perform reassessments along with 
the lengthened reassessment intervals provided in ASME/ANSI B31.8S.
    Response: RSPA/OPS has made significant changes to the cost-benefit 
analysis. Included in these changes is full consideration of the impact 
of the Pipeline Safety Improvement Act of 2002. The Act significantly 
changed the regulatory environment in which the new rule will be 
implemented. The Act requires that gas transmission pipeline operators 
develop integrity management plans, perform risk analyses, and perform 
certain tests, including retests at specified intervals. These 
requirements forever change the regulatory landscape. The notice of 
proposed rulemaking was issued in January, only one month after the Act 
was signed into law. RSPA/OPS modified the notice to acknowledge that 
the law was passed and that it imposed some requirements, but RSPA/OPS 
had not taken time to analyze thoroughly the impacts the Act would 
have.
    RSPA/OPS has since performed extensive analyses to consider the 
impacts of the Act and to evaluate ways to make the rule more cost-
beneficial. RSPA/OPS has estimated the costs to implement the 
requirements in the Act, without modification, to be approximately $11 
billion over 20 years. By comparison, we conclude the cost of 
implementing this rule will be $4.7 billion over the same period. The 
difference reflects changes made in this rule in the definition of HCAs 
(which will have the effect of reducing the amount of pipeline mileage 
that must be tested) and provisions for limited scope reassessments 
every seven years. The Act requires that pipelines be assessed every 
seven years. The Act further requires that these assessments be 
performed using one of three specified assessment methods or ``an 
alternative method that the Secretary [of Transportation] determines 
would provide an equal or greater level of safety.'' The alternative 
methods included in this rule will reduce costs significantly over the 
cost of performing periodic assessments using only the methods 
specified in the Act. There is therefore a benefit in adopting this 
rule of approximately $6.2 billion in cost reduction for assuring 
pipeline integrity.
    Benefits will also accrue in improved ability to site pipelines in 
certain critical markets. It is difficult to quantify this benefit, but 
RSPA/OPS believes it is real. Inability to site future pipelines could 
affect the Nation's ability to use the increased quantities of natural 
gas that the Energy Information Administration estimates will be needed 
to fuel our economy over the next 20 years.
    The rule will significantly reduce the likelihood of pipeline 
accidents that result in deaths and serious injuries. Based on the 
historical record, RSPA/OPS has estimated this benefit to be on

[[Page 69801]]

the order of $800 million over 20 years. It is quite likely, though, 
that future accidents could be worse than the historical experience. 
Population near pipelines is growing. This places more people at risk 
than in the past. While some historical accidents have resulted in 
several deaths and serious injuries, and significant property damage, 
accidents with even greater consequences could occur. RSPA/OPS has 
analyzed the likelihood that an accident could occur in an area along 
the pipeline that is more densely populated. Even though the amount of 
pipeline mileage along which such high population densities might be 
found is small (RSPA/OPS estimated 0.1% of total mileage for this 
analysis) the consequences of an accident are potentially large enough 
that the averted costs are still high. RSPA/OPS estimates that an 
additional $277 million is realized by avoiding the likelihood of this 
more significant accident.
    The rule will also result in avoiding significant costs associated 
with unexpected interruptions in natural gas supply. The Carlsbad 
accident in 2000 resulted in curtailment of supply of natural gas to 
California. RSPA/OPS estimates that this resulted in an impact on the 
California economy of $17.25 million per day. The total benefit 
afforded by this rule in avoiding future economic impacts of this type 
is estimated to be $1 billion over the next 20 years.
    Another benefit to be realized from implementing this rule is 
reduced cost to the pipeline industry for assuring safety in areas 
along pipelines with relatively more population. The improved knowledge 
of pipeline integrity that will result from implementing this rule will 
provide a technical basis for providing relief to operators from 
current requirements to reduce operating stresses in pipelines when 
population near them increases. Regulations currently require that 
pipelines with higher local population density operate at lower 
pressures. This is intended to provide an extra safety margin in those 
areas. Operators typically replace pipeline when population increases, 
because reducing pressure to reduce stresses reduces the ability of the 
pipeline to carry gas. Areas with population growth typically require 
more, not less, gas. Replacing pipeline, however, is very costly. 
Providing safety assurance in another manner, such as by implementing 
this rule, could allow RSPA/OPS to waive some pipe replacement. RSPA/
OPS estimates that such waivers could result in a reduction in costs to 
industry of $1 billion over the next 20 years, with no reduction in 
public safety.
    A more detailed discussion of how public comments were addressed in 
the revised cost-benefit analysis can be found in the final regulatory 
analysis.

The Final Rule

    RSPA/OPS has created a new Subpart O in Part 192 for Pipeline 
Integrity Management and reformatted the rule into sections analogous 
to existing Part 192 rules. RSPA/OPS recognizes that a simple format 
and clarity are important features to assist pipeline operators in 
using and complying with each requirement.

Section 192.901 What Do the Regulations in This Subpart Cover?

    The new Subpart O prescribes minimum requirements for an integrity 
management program on gas transmission pipelines that could affect an 
HCA. HCAs are defined in Sec.  192.903, and Sec.  192.905 describes how 
an operator identifies these areas. Section 192.905 is based on the 
recent guidance RSPA/OPS issued on how to identify these areas. The 
definitions of gas and transmission pipeline are found in Sec.  192.3. 
This final rule does not apply to gas gathering pipelines or to gas 
distribution pipelines. Because most of the requirements are applicable 
to metal pipelines, not plastic, only certain requirements apply to 
plastic gas transmission pipelines. Requirements for a continuing 
threat analysis (Sec. Sec.  192.917, 192.937), a baseline assessment if 
a threat other than third-party damage is identified (Sec.  192.921), 
and additional preventive and mitigative measures (Sec.  192.935) apply 
to plastic gas transmission pipelines.

Section 192.903 What Definitions Apply to This Subpart?

    In the final rule RSPA/OPS has made changes to the definitions in 
the new Sec.  192.903 based on the petition for reconsideration, 
written comments in the docket, comments received at post-NPRM public 
meetings and the recommendations given by the gas advisory committee. 
The proposed definitions Potential Impact Zone, Threshold Radius, and 
Moderate Risk Areas have been deleted. New definitions of Assessment, 
Covered pipeline segment, Identified site, and Remediation have been 
added.
    The High consequence area definition was modified to allow an 
operator two methods to identify the areas.
    In method (a) high consequence areas are--
    1. Current Class 3 location;
    2. Current Class 4 location;
    3. Any areas areas outside a Class 3 or 4 location where the 
Potential Impact Radius is greater than 660 feet (200 meters), and the 
area within a Potential Impact Circle contains 20 or more buildings 
intended for human occupancy. However, if the radius of the Potential 
Impact Circle is greater than 660 feet (200 meters), the operator may 
identify a high consequence area based on a prorated number of 
buildings intended for human occupancy within a distance 660 feet (200 
meters) from the centerline of the pipeline until December 17, 2006. If 
an operator chooses this approach, the operator must prorate the number 
of buildings intended for human occupancy based on the ratio of an area 
with a radius of 660 feet (200 meters) to the area of the Potential 
Impact Circle (i.e., the prorated number of buildings intended for 
human occupancy is equal to [20 x (660 feet [or 200 meters ]/Potential 
Impact Radius in feet [or meters]) \2\]).
    4. The area within a Potential Impact Circle containing an 
identified site.
    In method (b) high consequence areas are--
    1. The area within a Potential Impact Circle containing 20 or more 
buildings intended for human occupancy, (unless the exception described 
above in method (a) applies);
    2. The area within a Potential Impact Circle containing an 
identified site.
    When a Potential Impact Circle is calculated under either of the 
methods to establish a high consequence area, the length of the high 
consequence area extends axially along the length of the pipeline from 
the outermost edge of the first Potential Impact Circle that contains 
an identified site or 20 or more buildings intended for human occupancy 
to the outermost edge of the last contiguous Potential Impact Circle 
that contains either an identified site or 20 or more buildings 
intended for human occupancy. Appendix E, Figure E.I.A gives a graphic 
representation.
    The identified site component of the high consequence area 
definition was also modified to distinguish between rural buildings and 
outside open areas and to simplify the identification process. An 
identified site is an area meeting one of three criteria--
    1. An outside area or open structure that is occupied by twenty 
(20) or more persons on at least 50 days in any twelve (12) month 
period (the days need not be consecutive). Examples included in the 
definition are beaches, playgrounds, recreational facilities, camping 
grounds, outdoor theaters, stadiums, recreational areas near a body of 
water, or areas outside a rural building such as a religious facility, 
or

[[Page 69802]]

    2. A building that is occupied by twenty (20) or more persons on at 
least five (5) days a week for ten (10) weeks in any twelve (12) month 
period (the days and weeks need not be consecutive). Examples included 
in the definition are religious facilities, office buildings, community 
centers, general stores, 4-H facilities, and roller rinks.
    3. A facility occupied by persons who are confined, are of impaired 
mobility, or would be difficult to evacuate. Examples included in the 
definition are hospitals, prisons, schools, day-care facilities, 
retirement facility and assisted-living facilities.

Section 192.905 How Does an Operator Identify a High Consequence Area?

    An operator is required to select method (a) or method (b) from the 
definition in Sec.  192.903 to identify a high consequence area. One 
method may be applied to an entire pipeline system, or the methods may 
be applied individually to portions of the pipeline system. An operator 
has to describe in its integrity management program which method is 
applicable for each portion of the operator's system, and show the 
Potential Impact Radius when utilized for each covered segment. The 
rule also includes guidance in Appendix E.I. on identifying HCAs.
    This section also prescribes how an operator must identify HCAs 
that include ``identified sites.'' The rule is consistent with the 
advisory bulletin RSPA/OPS recently issued (68 FR 42458). An operator 
identifies an identified site from information the operator has 
obtained from routine operation and maintenance activities and from 
public officials with safety or emergency response or planning 
responsibilities who indicate to the operator that they know of 
locations that meet the identified site criteria. These public 
officials could include officials on a local emergency planning 
commission or relevant Native American tribal officials.
    The rule further provides that if a public official with safety or 
emergency response or planning responsibilities informs an operator 
that she/he does not have the information to identify an identified 
site, the operator is required to use one of several listed sources, as 
appropriate, to identify these sites. The listed sources include--
    1. Visible marking (e.g., a sign); or
    2. The site is licensed or registered by a Federal, State, or local 
government agency; or
    3. The site is on a list (including a list on an Internet Web site) 
or map maintained by or available from a Federal, State, or local 
government agency and available to the general public.
    The rule provides requirements for identifying new HCAs. When an 
operator has information that the area around a pipeline segment not 
previously identified as a high consequence area could satisfy any of 
the definitions of a high consequence area (as defined in Sec.  
192.903), the operator must complete the evaluation using 
identification method (1) or (2). If the segment is determined to meet 
the definition as a high consequence area, then it must be incorporated 
into the operator's baseline assessment plan as a high consequence area 
within one year from the date the area is identified.

Section 192.907 What Must an Operator Do To Implement This Subpart?

    The rule requires that no later than December 17, 2004, an operator 
must develop and follow a written integrity management program that 
contains all the elements described in Sec.  192.911 and that addresses 
the risks on each covered transmission pipeline segment. The one-year 
time frame is based on the statutory requirement to issue regulations 
requiring an operator to conduct a risk analysis and adopt an integrity 
management program no later than December 17, 2004. Initially, the 
integrity management program can consist of a framework that describes 
the process for implementing each program element, how relevant 
decisions will be made and by whom, a time line for completing the work 
to implement the program element, and how information gained from 
experience will be continuously incorporated into the program. The 
framework will evolve into a more detailed and comprehensive program. 
An operator must make continual improvements to the program.
    The rule requires an operator to follow ASME/ANSI B31.8S, and its 
appendices, where specified, as well as the requirements in Subpart O 
in implementing its integrity management program. ASME/ANSI B31.8S, the 
Supplement to ASME/ANSI B31.8, is an industry consensus standard that 
specifically addresses system integrity of gas pipelines. The rule 
allows an operator to follow an equivalent standard or practice only 
when the operator demonstrates the alternative standard or practice 
provides an equivalent level of safety to the public and property. The 
rule clarifies that in the event of a conflict between Subpart O and 
ASME/ANSI B31.8S, the requirements in Subpart O control.

Section 192.909 How Can an Operator Change Its Integrity Management 
Program?

    The rule requires that prior to implementing any change to its 
program, an operator must document the change and the reasons for the 
change, and notify OPS within 30 days after the operator adopts the 
change into its program. The notification is required for any change to 
the program that--
    [sbull] May substantially affect the program's implementation; or
    [sbull] May significantly modify the program or schedule for 
carrying out the program elements.
    An operator must also notify a State or local pipeline safety 
authority when a covered segment is located in a State where OPS has an 
interstate agent agreement and a State or local pipeline safety 
authority that regulates a covered pipeline segment within that State.

Section 192.911 What Are the Elements of an Integrity Management 
Program?

    The rule requires an operator to include certain minimum elements 
in its integrity management program. Minimum elements are those listed 
in the rule and when referenced in the rule those in the ASME/ANSI 
B31.8S standard. The Supplement to ASME/ANSI B31.8 is an industry 
standard that specifically addresses system integrity of gas pipelines. 
The required program elements include:
    [sbull] An identification of all high consequence areas.
    [sbull] A baseline assessment plan. Requirements governing these 
plans are in Sec.  192.919 and Sec.  192.921.
    [sbull] An identification of threats to each covered pipeline 
segment, which must include data integration and a risk assessment to 
evaluate the failure likelihood of each covered segment. An operator 
must use the threat identification and risk assessment to prioritize 
covered segments for assessment (Sec.  192.917) and to evaluate the 
merits of additional preventive and mitigative measures (Sec.  192.935) 
for each covered segment.
    [sbull] A direct assessment plan, if the operator is going to use 
direct assessment. The plan must comply with Sec.  192.923, and 
depending on the threat assessed, with Sec.  192.925 (external 
corrosion), Sec.  192.927 (internal corrosion), or Sec.  192.929 
(stress corrosion cracking).
    [sbull] Provisions for remediating conditions found during an 
integrity assessment. (Sec.  192.933.)
    [sbull] A process for continual evaluation and assessment. (Sec.  
192.937.)

[[Page 69803]]

    [sbull] A plan for confirmatory direct assessment (Sec.  192.931) 
if the operator plans to use this method for reassessment.
    [sbull] Provisions for adding preventive and mitigative measures to 
protect the high consequence area. (Sec.  192.935.)
    [sbull] A performance plan as outlined in Section 9 of ASME/ANSI 
B31.8S that includes the required performance measures in Sec.  
192.943.
    [sbull] Record keeping provisions (Sec.  192.947).
    [sbull] A management of change process as outlined in Section 11 of 
ASME/ANSI B31.8S.
    [sbull] A quality assurance process as outlined in Section 12 of 
ASME/ANSI B31.8S.
    [sbull] A communication plan that includes the elements of Section 
10 of ASME/ANSI B31.8S, and that includes procedures for addressing 
safety concerns raised by (1) OPS; and (2) a State or local pipeline 
safety authority when a covered segment is located in a State where OPS 
has an interstate agent agreement. This process for addressing safety 
concerns raised by interstate agents is a requirement imposed by 
statute.
    [sbull] Procedures for providing (when requested), by electronic or 
other means, a copy of the operator's risk analysis or integrity 
management program to OPS or to a State or local pipeline safety 
authority when a covered segment is located in a State where OPS has an 
interstate agent agreement. This requirement to provide the information 
to an interstate agent is imposed by statute.
    [sbull] Procedures for ensuring that each integrity assessment is 
being conducted in a manner that minimizes environmental and safety 
risks.
    [sbull] A process for identification and assessment of newly-
identified high consequence areas.(Sec.  192.905 and Sec.  192.921)

Section 192.913 When May an Operator Deviate Its Program From Certain 
Requirements of This Subpart and Use a Performance-Based Option?

    ASME/ANSI B31.8S allows an operator to deviate from some specific 
provisions of the standard if the operator has a mature integrity 
management program that addresses the intent of those provisions in a 
different manner. This is called a performance-based program, as 
compared to a prescriptive program (i.e., one meeting the literal 
provisions of the standard). The rule describes the essential features 
of a performance-based or a prescriptive integrity management program. 
The rule allows an operator to deviate from certain integrity 
management program requirements if it has a performance-based program 
that has demonstrated exceptional performance.
    To qualify for exceptional performance an operator must--
    [sbull] Have completed at least two integrity assessments of all 
covered pipeline segments.
    [sbull] Be able to demonstrate that each assessment effectively 
addressed the identified threats on the covered segments.
    [sbull] Remediate all anomalies identified in the more recent 
assessment according to the remediation requirements in the rule. The 
remediation requirements are set forth in Sec.  192.933.
    [sbull] Incorporate the results and lessons learned from the more 
recent assessment into the operator's data integration and risk 
assessment.
    [sbull] Have a performance-based integrity management program that 
meets or exceeds the performance-based requirements of ASME/ANSI 
B31.8S, and includes certain minimum elements. The minimum elements 
are: (1) A comprehensive process for risk analysis; (2) all risk factor 
data used to support the program; (3) A comprehensive data integration 
process; (4) A procedure for applying lessons learned from assessment 
of covered pipeline segments to non covered pipeline segments. A 
covered segment is one within the scope of Subpart O; (5) A procedure 
for evaluating incidents within the operator's sector of the pipeline 
industry for implications both to the operator's pipeline system and to 
the operator's integrity management program; (6) A performance matrix 
that demonstrates the program has been effective in ensuring the 
integrity of the covered segments by controlling the identified threats 
to the covered segments; (7) Semi-annual performance measures beyond 
those required in Sec.  192.943 that are part of the operator's 
performance plan (see Sec.  192.911(i)); and (8) An analysis that 
supports the desired integrity reassessment interval and the 
remediation methods to be used for all covered segments.
    Once an operator has demonstrated that it has satisfied the 
requirements for exceptional performance, the operator may deviate from 
the prescriptive requirements of ASME/ANSI B31.8S and of Subpart O in 
two instances:
    [sbull] The time frame for reassessment as provided in Sec.  
192.939 except that reassessment by an allowable method (e.g., 
confirmatory direct assessment) must be carried out at intervals no 
longer than seven years; and
    [sbull] The time frame for remediation as provided in Sec.  
192.933, as long as the operator demonstrates that the revised time 
frame will not jeopardize the safety of the covered segment.

Section 192.915 What Knowledge and Training Must Personnel Have To 
Carry Out an Integrity Management Program?

    The rule has requirements for supervisory personnel and for other 
personnel with integrity management program functions. These 
requirements apply to both personnel employed by the operator and 
contractor personnel used to perform integrity management program 
functions.
    For supervisory personnel, the integrity management program must 
provide that each supervisor whose responsibilities relate to the 
integrity management program possesses and maintains a thorough 
knowledge of the integrity management program and of the elements for 
which he or she is responsible. The program must provide that any 
person who qualifies as a supervisor for the integrity management 
program has appropriate training or experience in the area for which 
the person is responsible.
    The integrity management program must provide criteria for the 
qualification of any person
    [sbull] Who conducts assessments;
    [sbull] Who reviews and analyzes the results from an integrity 
assessment; or
    [sbull] Who makes decisions on actions to be taken based on these 
assessments.
    The program must also include criteria for the qualification of 
persons
    [sbull] Who implement preventive and mitigative measures to carry 
out the requirements of the rule, including the marking and locating of 
buried structures; or
    [sbull] Who directly supervise excavation work carried out in 
conjunction with an integrity assessment.

Section 192.917 How Does an Operator Identify Potential Threats to 
Pipeline Integrity and Use the Threat Identification in Its Integrity 
Program?

    The rule requires that an operator's integrity management program 
begin with an identification of the potential threats to which the 
pipeline is subjected. The program then is constructed to deal with 
those threats.
    Threat identification. The rule requires an operator to identify 
and evaluate all potential threats to each covered pipeline segment. 
These potential threats include, but are not limited to:
    [sbull] The threats listed in Section 2 of ASME/ANSI B31.8S and
    [sbull] Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;

[[Page 69804]]

    [sbull] Static or resident threats, such as fabrication or 
construction defects;
    [sbull] Time independent threats such as third-party damage and 
outside force damage; and
    [sbull] Human error.
    Data gathering and integration. The rule requires that to identify 
and evaluate the potential threats to a covered pipeline segment, an 
operator must gather and integrate data and information concerning the 
entire pipeline that could be relevant to the covered segment. Section 
4 of ASME/ANSI B31.8S provides requirements for performing this data 
gathering and integration, and the operator must follow those 
requirements. At a minimum, an operator has to gather and evaluate the 
set of data specified in Appendix A to ASME/ANSI B31.8S, and consider 
both on the covered segment and similar non-covered segments, past 
incident history, corrosion control records, continuing surveillance 
records, patrolling records, maintenance history, internal inspection 
records and all other conditions specific to each pipeline.
    Risk assessment. The rule requires an operator to conduct a risk 
assessment that follows Section 5 of ASME/ANSI B31.8S and considers the 
identified threats for each covered segment, and then use the risk 
assessment to prioritize the covered segments for the baseline and 
continual reassessments (Sec. Sec.  192.919, 192.921, 192.937), and to 
determine what additional preventive and mitigative measures are needed 
(Sec.  192.935).
    On a plastic transmission pipeline, an operator has to conduct a 
threat analysis to the covered segments by using data on threats unique 
to plastic pipe, and information in Sections 4 and 5 of ASME/ANSI 
B31.8S. A good source of data information may be found in plastic pipe 
database collection (PPDC) with AGA.
    Particular threats. The rule requires that an operator take 
specific actions to address particular threats the operator has 
identified. Those threats, and the required actions, are for third-
party damage, cyclic fatigue, manufacturing and construction defects, 
ERW or lap welded pipe, and corrosion. These threats have been 
identified for specific action because of their significance to 
pipeline integrity and because the unique operational characteristics 
of gas transmission pipelines dictate that they be treated uniquely. 
The primary difference in the operation of gas transmission pipeline 
related to these defects is the absence of significant pressure cycling 
and the associated absence of the cyclic fatigue driving force for 
crack growth. The absence of significant cyclic fatigue implies that 
the failure of pipelines from these threats has unique causes that need 
to be addressed in an integrity management program for gas transmission 
pipelines.
    An operator must utilize the required data integration and Appendix 
A7 of ASME/ANSI B31.8S to determine the susceptibility of each covered 
segment to the threat of third-party damage. If an operator identifies 
the threat of third-party damage, the operator--
    [sbull] Must implement comprehensive additional preventive measures 
in accordance with Sec.  192.935 and monitor the effectiveness of the 
preventive measures.
    [sbull] If, in conducting a baseline assessment under Sec.  191.921 
or a reassessment under Sec.  192.937, an operator uses an internal 
inspection tool, such as a caliper, geometry or magnetic flux leakage 
tool to address other identified threats on the covered segment, the 
operator must integrate data from these tool runs with data related to 
any encroachment or foreign pipeline crossing on the covered segment, 
to define where potential indications of third-party damage may exist 
in the covered segment.
    [sbull] Have a procedure in its integrity management program 
addressing actions it will take in response to findings from this data 
integration.
    The rule requires an operator to evaluate whether cyclic fatigue or 
other loading conditions (including ground movement, suspension bridge 
condition) could lead to a failure of a deformation, including a dent 
or gouge, or other defect in the covered segment. The evaluation must 
include an assumption that there are threats in the covered segment 
that could be exacerbated by cyclic fatigue. An operator must use the 
results from the evaluation together with the criteria used to evaluate 
the significance of this threat to the covered segment and to 
prioritize the integrity assessment.
    The rule requires that if an operator identifies the threat of 
manufacturing and construction defects (including seam defects) in the 
covered segment, the operator must analyze the covered segment to 
determine the risk of failure from these mechanisms. Manufacturing and 
construction related defects are considered to be stable defects if the 
operating conditions have not significantly changed since December 17, 
1998, since successful operation demonstrates that the defects do not 
threaten pipeline integrity. Changes in operating conditions, such as a 
significant increase in pressure, could cause latent defects to grow. 
Therefore, if the pipeline operating conditions change such that 
operating pressure will be above the historic operating pressure, if 
MAOP increases, or if stresses that could lead to cyclic fatigue 
increase, the operator must treat the covered segment as a high-risk 
segment.
    If a covered pipeline segment contains low frequency electric 
resistance welded pipe (ERW) or lap welded pipe that satisfies the 
conditions specified in Appendix A4.3 and A4.4 of ASME/ANSI B31.8 S, 
the rule requires an operator to select an assessment technology or 
technologies capable of assessing seam integrity and of detecting seam 
corrosion anomalies. The operator must prioritize the covered segment 
as a high risk segment for the baseline assessment or reassessment. If 
an operator finds corrosion on a covered pipeline segment that could 
adversely affect the integrity of the pipeline; the operator has to 
evaluate and remediate, as necessary, all pipeline segments (both 
covered and non-covered) where similar corrosion might be found (i.e., 
with similar material coating and environmental characteristics). The 
evaluation and remediation, if remediation is needed, must be completed 
in a time frame consistent with the operator's operation and 
maintenance procedures under part 192 for required testing and repair.

Section 192.919 What Must Be in the Baseline Assessment Plan?

    Each operator's integrity management program must contain a 
baseline assessment plan that has certain elements. These elements 
are--
    (a) Identification of the potential threats to each covered 
pipeline segment and the information supporting the threat 
identification. Requirements are in Sec.  192.917.
    (b) The methods selected to assess the integrity of the line pipe, 
including an explanation of why the assessment method was selected to 
address the identified threats affecting each covered segment. The 
methods allowed are listed in Sec.  192.921 and include internal 
inspection, pressure test, direct assessment or alternative equivalent 
technology. More than one method may be required to address all the 
threats to the covered pipeline segment;
    (c) A schedule for completing the integrity assessment of all 
covered segments, including the risk factors considered in establishing 
the assessment schedule;
    (d) If an operator plans to use direct assessment, a direct 
assessment plan that complies with the requirements in Sec.  192.923, 
and depending on the threat

[[Page 69805]]

for which direct assessment is used, Sec.  192.925 (external 
corrosion), Sec.  192.927 (internal corrosion), or Sec.  192.929 
(stress corrosion cracking).
    (e) A procedure to ensure that the baseline assessment is conducted 
in a manner that minimizes environmental and safety risks.

Section 192.921 How Is the Baseline Assessment To Be Conducted?

    The rule requires an operator assess the integrity of the line pipe 
in each covered segment by using one or more of the allowable 
assessment methods. An operator has to select the method or methods 
best suited to address the threats identified for each covered segment. 
Threat identification requirements are in Sec.  192.917. The methods 
the rule allows are:
    (1) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the covered segment is 
susceptible. An operator must follow Section 6.2 of ASME/ANSI B31.8S in 
selecting the appropriate internal inspection tools for the covered 
segment.
    (2) Pressure test conducted in accordance with Subpart J of 49 CFR 
Part 192;
    (3) Direct assessment for the threats of external corrosion, 
internal corrosion, and stress corrosion cracking. An operator must 
conduct the direct assessment in accordance with the requirements 
listed in Sec.  192.923 and with, as applicable, the requirements 
specified in Sec. Sec.  192.925, 192.927 or 192.929. Requirements 
depend on the threat the operator is using direct assessment to 
address.
    (4) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
intending to use other technology must notify the Office of Pipeline 
Safety (OPS) in accordance with the notification requirements in Sec.  
192.949, 180 days before conducting the assessment, so that OPS has an 
opportunity to review those intentions.
    The rule requires an operator to prioritize the covered pipeline 
segments for the baseline assessment according to a risk analysis that 
considers the potential threats identified for each covered segment. 
The risk analysis must comply with the requirements in Sec.  192.917. 
To choose an assessment method for the baseline assessment of each 
covered segment, an operator must take the actions required to address 
particular threats that it has identified. These actions are set forth 
in Sec.  192.917.
    The rule sets time periods for the baseline assessment. These time 
periods were set by statute. The statute requires that the baseline be 
completed not later than ten years after date of enactment (December 
17, 2002) and at least 50% of the facilities assessed no later than 
five years after date of enactment. Thus, the rule requires an operator 
to assess at least 50% of the covered segments beginning with the 
highest risk segments, by December 17, 2007, and complete the baseline 
assessment of all covered segments by December 17, 2012.
    The rule allows prior assessments conducted before the date the act 
mandating integrity management programs for gas operators was signed 
into law (December 17, 2002) to be used as baseline assessments. An 
operator may use a prior integrity assessment as a baseline assessment 
for the covered segment, if the integrity assessment meets the baseline 
requirements in Subpart O and the operator has taken subsequent 
remedial actions to address the conditions that are listed in Sec.  
192.933. However, if an operator uses this prior assessment as its 
baseline assessment, the operator must reassess the line pipe in the 
covered segment according to the reassessment requirements of 
Sec. Sec.  192.937and 192.939. The reassessment of the covered segment 
must be done no later than December 17, 2009.
    The rule requires that when an operator identifies a new high 
consequence area, the baseline assessment of the line pipe in that area 
be completed within 10 years from the date the area is identified.
    On newly-installed pipe, a baseline assessment has to be done 
within ten years from the date the pipe is installed. If a post-
installation pressure test has been conducted on the new pipe in 
accordance with Subpart J, that pressure test satisfies the baseline 
assessment requirement.
    For plastic transmission pipelines an operator has to conduct a 
baseline assessment of a covered segment if the operator has identified 
a threat, other than third-party damage to the segment. The operator 
will have to justify the assessment method the operator intends to use.

Section 192.923 How Is Direct Assessment Used and for What Threats?

    The rule allows an operator to use direct assessment either as a 
primary assessment method or as a supplement to the other assessment 
methods allowed under this subpart. If used as the primary assessment 
method, it can only be used to address the identified threats of 
external corrosion (ECDA), internal corrosion (ICDA), or stress 
corrosion cracking (SCCDA).
    The rule requires an operator to have a direct assessment plan. The 
requirements for the plan depend on the threat being addressed. If 
addressing external corrosion, the plan must comply with the 
requirements in Section 6.4 of ASME/ANSI B31.8S; NACE RP0502-2002; and 
Sec.  192.925. If addressing internal corrosion, the plan must comply 
with Section 6.4 and Appendix B2 of ASME/ANSI B31.8S, and Sec.  
192.927. And if direct assessment is used to address stress corrosion 
cracking, the plan must comply with Appendix A3 of ASME/ANSI B31.8S, 
and Sec.  192.929.
    If direct assessment is used as a supplemental assessment method 
the plan must follow the requirements for confirmatory direct 
assessment in Sec.  192.931.

Section 192.925 What Are the Requirements for Using External Corrosion 
Direct Assessment (ECDA)?

    This section specifies requirements an operator must follow in 
using External Corrosion Direct Assessment (ECDA). The rule defines 
ECDA as a four-step process that combines preassessment, indirect 
inspections, direct examination, and post assessment to evaluate the 
impact of external corrosion on the integrity of a pipeline.
    The rule requires the operator to follow Section 6.4 of ASME/ANSI 
B31.8S, and NACE RP 0502-2002. The Supplement to ASME/ANSI B31.8 is an 
industry standard that specifically addresses system integrity of gas 
pipelines. The NACE standard is an industry recommended practice that 
addresses methodology for a pipeline external corrosion direct 
assessment. The rule requires an operator's direct assessment plan to 
have procedures addressing preassessment, indirect inspections, direct 
examination, and post-assessment. For all four steps, the procedures 
must provide for applying more restrictive criteria when conducting 
ECDA for the first time on a covered segment.
    The preassessment procedures must follow the requirements in 
Section 6.4 of ASME/ANSI B31.8S and Section 3 of NACE RP 0502-2002, and 
also include the basis on which the operator selects at least two 
different, but complementary indirect assessment tools to assess each 
ECDA Region. If an operator utilizes an indirect inspection method that 
is not discussed in Appendix A of NACE RP0502-2002, the operator must 
demonstrate the applicability, validation basis, equipment used, 
application procedure and utilization of data for the inspection 
method.

[[Page 69806]]

    The plans procedures for indirect examination must follow the 
requirements in Section 6.4 of ASME/ANSI B31.8S and Section 4 of NACE 
RP0502-2002, and include criteria for:
    [sbull] Identifying and documenting those indications that must be 
considered for excavation and direct examination;
    [sbull] For defining the urgency of excavation and direct 
examination of each indication identified during the direct 
examination; and
    [sbull] For scheduling excavation of indications for each urgency 
level.
    The procedures for direct examination must follow the requirements 
in Section 6.4 of ASME/ANSI B31.8S and Section 5 of NACE RP0502-2002, 
and include criteria for:
    [sbull] Deciding what action should be taken if either corrosion 
defects are discovered that exceed allowable limits (Section 5.5.2.2 of 
NACE RP0502-2002), or root cause analysis reveals conditions for which 
ECDA is not suitable (Section 5.6.2 of NACE RP0502-2002);
    [sbull] For any changes in the ECDA Plan, including changes that 
affect the severity classification, the priority of direct examination, 
and the time frame for direct examination of indications; and
    [sbull] That describe how and on what basis an operator will relax 
any of the criteria that NACE RP0502-2002 specifies can be relaxed.
    The plan's procedures for post assessment of the effectiveness of 
the ECDA process must follow the requirements in Section 6.4 of ASME/
ANSI B31.8S and Section 6 of NACE RP0502-2002, and also include 
measures for evaluating the long-term effectiveness of ECDA in 
addressing external corrosion in covered segments and criteria for 
evaluating whether conditions discovered by direct examination of 
indications in each ECDA region indicate a need for reassessment of the 
covered segment at an interval less than that specified in Sec.  
192.939. (Appendix D of NACE RP0502-2002 provides guidance for 
performing this evaluation).

Section 192.927 What Are Requirements for Using Internal Corrosion 
Direct Assessment (ICDA)?

    This section specifies requirements an operator must follow in 
using Internal Corrosion Direct Assessment (ICDA). An operator must 
follow the requirements in Section 6.4 and Appendix B2 of ASME/ANSI 
B31.8S, as well as those listed in this section. The ICDA process 
described in this rule applies only for a segment of pipe transporting 
nominally dry natural gas and not for a segment with electrolyte 
nominally present in the gas stream. If an operator uses ICDA to assess 
a covered segment operating with electrolyte present in the gas stream, 
the operator must develop a plan that demonstrates how it will conduct 
ICDA in the segment to effectively address internal corrosion.
    The rule defines ICDA as a process an operator can use to identify 
areas along the pipeline where fluid or other electrolyte that might be 
introduced during normal operation or by an upset condition may reside. 
ICDA then focuses direct examination on the locations in each area 
where internal corrosion is most likely to exist. The process 
identifies the potential for internal corrosion caused by 
microorganisms, or fluid with CO2, O2, hydrogen 
sulfide or other contaminants present in the gas.
    The rule requires that an operator's ICDA plan must provide for 
preassessment, identification of ICDA regions and excavation locations, 
detailed examination of pipe at excavation locations, and post-
assessment evaluation and monitoring.
    In the preassessment stage, an operator must gather and integrate 
data and information needed to evaluate the feasibility of ICDA for the 
covered segment, to identify the locations in the covered segment where 
electrolyte may accumulate, to identify ICDA regions within the covered 
segment, and to support the use of a model to identify areas within the 
covered segment where liquids may potentially be entrained. This data 
and information includes, but is not limited to--
    [sbull] All data elements listed in Appendix A2 of ASME/ANSI 
B31.8S.
    [sbull] Information needed to support use of a model that an 
operator must use to identify areas along the pipeline where internal 
corrosion is most likely to occur. This information, includes, but is 
not limited to, location of all gas input and withdrawal points on the 
pipeline; location of all low points on covered segments such as sags, 
drips, inclines, valves, manifolds, dead-legs, and traps; the elevation 
profile of the pipeline in sufficient detail that angles of inclination 
can be calculated for all pipe segments; and the diameter of the 
pipeline, and the range of expected gas velocities in the pipeline.
    [sbull] Operating experience data that would indicate historic 
upsets in gas conditions, locations where these upsets have occurred, 
and potential damage resulting from these upset conditions.
    [sbull] Identification of covered segments where cleaning pigs may 
not have been used or where cleaning pigs may deposit electrolytes.
    The plan must define all ICDA Regions within each covered pipeline 
segment. An ICDA region extends from the location where liquid may 
first enter the pipeline and encompasses the entire area along the 
pipeline where internal corrosion may occur and where further 
evaluation is needed. In the identification process, an operator must 
use the model in GRI 02-0057 ``Internal Corrosion Direct Assessment of 
Gas Transmission Pipelines--Methodology'' or an equivalent model if the 
operator demonstrates it is equivalent to the GRI model. A model must 
consider changes in pipe diameter, locations where gas enters a 
pipeline (potential to introduce liquid) and locations downstream of 
gas draw-offs (where gas velocity is reduced) to define the critical 
pipe angle of inclination above which water film cannot be transported 
by the gas.
    An operator's plan must identify the locations where internal 
corrosion is most likely in each ICDA region. In the location 
identification process, an operator must identify a minimum of two 
locations for excavation within each ICDA Region and must perform a 
direct examination for internal corrosion at each location, using 
ultrasonic thickness measurements, radiography, or other generally 
accepted measurement techniques. One location must be the low point 
(e.g., sags, drips, valves, manifolds, dead-legs, traps) nearest to the 
beginning of the ICDA Region, and the second must be at the upstream 
end of the pipe containing a covered segment, having a slope not 
exceeding the critical angle of inclination nearest the end of the ICDA 
Region. If corrosion exists at either location, the operator must 
evaluate the severity of the defect (remaining strength) and remediate 
the defect in accordance with Sec.  192.933; as part of the operator's 
current integrity assessment either perform additional excavations in 
covered segments within the ICDA region or use an alternative allowed 
assessment method to assess the line pipe in the covered segment for 
internal corrosion; and evaluate the potential for internal corrosion 
in all pipeline segments (both covered and non-covered) in the 
operator's pipeline system with similar characteristics to the covered 
segment in which the corrosion was found, and as appropriate, remediate 
the conditions the operator finds in accordance with Sec.  192.933.
    An operator's plan must provide for evaluating the effectiveness of 
the ICDA process and continued monitoring of covered segments where 
internal corrosion has been identified. The evaluation and monitoring 
process includes:

[[Page 69807]]

    [sbull] Evaluating the effectiveness of ICDA as an assessment 
method for addressing internal corrosion and determining whether a 
covered segment should be reassessed at more frequent intervals than 
those specified in Sec.  192.939. This evaluation must be carried out 
in the same year in which ICDA used.
    [sbull] Continually monitoring each covered segment where internal 
corrosion has been identified using techniques such as coupons, UT 
sensors or electronic probes, periodically drawing off liquids at low 
points and chemically analyzing the liquids for the presence of 
corrosion products. An operator must base the frequency of the 
monitoring and liquid analysis on results from all integrity 
assessments that have been conducted in accordance with the integrity 
management program rule, and risk factors specific to the covered 
segment. If an operator finds any evidence of corrosion products in the 
covered segment, the operator must take one of two required actions and 
remediate the conditions the operator finds in accordance with Sec.  
192.933. These actions are to conduct excavations of covered segments 
at locations downstream from where the electrolyte might have entered 
the pipe, or to assess the covered segment using another integrity 
assessment method allowed by this subpart.
    The ICDA plan must also include criteria an operator will apply in 
making key decisions (e.g., ICDA feasibility, definition of ICDA 
Regions, conditions requiring excavation) in implementing each stage of 
the ICDA process, and provisions for applying more restrictive criteria 
when conducting ICDA for the first time on a covered segment and that 
become less stringent as the operator gains experience and for carrying 
out an analysis on the entire pipeline in which covered segments are 
present, but limiting excavation and remediation to the covered 
segments.

Section 192.929 What Are the Requirements for Using Direct Assessment 
for Stress Corrosion Cracking (SCCDA)?

    This section specifies requirements an operator must follow in 
using direct assessment for stress corrosion cracking (SCCDA) which is 
defined as a process to assess a covered pipe segment for the presence 
of SCC primarily by systematically gathering and analyzing excavation 
data for pipe having similar operational characteristics and residing 
in a similar physical environment.
    The rule provides that an operator's direct assessment plan to 
identify this threat must at least provide for a systematic process to 
collect and evaluate data for all covered segments to identify whether 
the conditions for SCC are present and to prioritize the covered 
segments for assessment. This process must include gathering and 
evaluating data related to SCC at all excavated sites during conduct of 
its operation where the criteria in Appendix A3.3 of ASME/ANSI B31.8S 
indicate the potential for SCC. This data includes at minimum, the data 
specified in Appendix A3 of ASME/ANSI B31.8S. The plan must further 
provide that if conditions for SCC are identified in a covered segment, 
the operator must assess the covered segment using an integrity 
assessment method specified in Appendix A3 of ASME/ANSI B31.8S, and 
remediate the threat in accordance with Appendix A3.4 of ASME/ANSI 
B31.8S.

Section 192.931 How May Confirmatory Direct Assessment (CDA) Be Used?

    Confirmatory direct assessment (CDA) is used where external or 
internal corrosion is the threat of concern to the covered segment. An 
operator is allowed to use CDA as a method to reassess the line pipe in 
a covered segment at seven-year intervals. The rule provides that an 
operator's CDA plan for identifying external corrosion must comply with 
the requirements for external corrosion direct assessment in Sec.  
192.925 with the following exceptions.
    [sbull] The procedures for indirect examination may allow for use 
of only one indirect examination tool suitable for the application.
    [sbull] The procedures for direct examination and remediation must 
provide that all immediate action indications must be excavated for 
each ECDA region and that at least one high risk indication that meets 
the criteria of scheduled action must be excavated in each ECDA region.
    An operator's CDA plan identifying internal corrosion must comply 
with the requirements for internal corrosion direct assessment in Sec.  
197.927 except that the plan's procedures for identifying locations for 
excavation may require excavation of only one high risk location in 
each ICDA region.
    The premise behind CDA is that it is used to confirm the acceptable 
integrity of a pipeline, already ensured by assessments in accordance 
with ASME/ANSI B31.8S. If confirmation is not successful, i.e., if 
problems are found, then an operator needs to take additional actions. 
If an assessment carried out using CDA reveals defects requiring 
remediation prior to the next scheduled assessment, the operator must 
schedule the next assessment at a time defined by the requirements in 
Section 6.2 and 6.3 of NACE RP 0502-2002. If the defect requires 
immediate remediation, then the operator must reduce pressure 
consistent with Sec.  192.933 until it has completed reassessment using 
one of the assessment techniques allowed in Sec.  192.937.

Section 192.933 What Actions Must Be Taken To Address Integrity Issues?

    The rule requires an operator to take prompt action to address all 
anomalous conditions that the operator discovers through the integrity 
assessment. In addressing all conditions, an operator must evaluate all 
anomalous conditions and must remediate those that could reduce a 
pipeline's integrity. An operator must be able to demonstrate that the 
remediation of the condition will ensure that the condition is unlikely 
to pose a threat to the integrity of the pipeline until the next 
reassessment of the covered segment. The rule gives an operator an 
option if it is unable to respond within the specified time limits for 
certain conditions. The operator can either temporarily reduce the 
operating pressure of the pipeline or take other action that ensures 
the safety of the covered segment. If pressure is reduced, an operator 
must determine the temporary reduction in operating pressure of the 
pipeline using ASME/ANSI B31G or RSTRENG or the operator must reduce 
the operating pressure to a level not exceeding 80% of the level at the 
time the condition was discovered. A reduction in operating pressure 
cannot exceed 365 days without an operator providing a technical 
justification that the continued pressure restriction will not 
jeopardize the integrity of the pipeline.
    Discovery of condition. It is important to know when a condition 
has been ``discovered'', because the time periods for remediation begin 
upon discovery. The rule provides that discovery of a condition occurs 
when an operator has adequate information about the condition to 
determine that it presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after 
conducting an integrity assessment, obtain sufficient information about 
a condition to make that determination, unless the operator 
demonstrates that the 180-day period is impracticable.
    Schedule for evaluation and remediation. The rule provides that an 
operator complete remediation of a condition according to a schedule 
that prioritizes the conditions for evaluation and remediation. Unless 
a special

[[Page 69808]]

requirement for remediating certain conditions applies (these are 
listed in the rule as immediate repair, one-year and monitored 
conditions), an operator must follow the schedule in Section 7, Figure 
4 of ASME/ANSI B31.8S. If an operator cannot meet the schedule for any 
condition, the operator must justify the reasons why it cannot meet the 
schedule and that the changed schedule will not jeopardize public 
safety. An operator must notify OPS if it cannot meet the schedule and 
cannot provide safety through a temporary reduction in operating 
pressure or other action. An operator must also notify a State or local 
pipeline safety authority when a covered segment is located in a State 
where OPS has an interstate agent agreement, and a State or local 
pipeline safety authority that regulates a covered pipeline segment 
within that State.
    Special requirements for scheduling remediation. The rule lists 
immediate repair conditions, one-year conditions and monitored 
conditions. If a condition is an immediate repair condition, the 
operator must either temporarily reduce operating pressure or shut down 
the pipeline until the repair is completed. The one-year period begins 
from when the condition is discovered. Certain dents on the top of the 
pipe are listed as one-year conditions. Monitored conditions are those 
that an operator must record and monitor during subsequent risk 
assessments and integrity assessments for any change that may require 
remediation.

Section 192.935 What Additional Preventive and Mitigative Measures Must 
An Operator Take To Protect the High Consequence Area?

    The requirements in this section apply to all gas transmission 
pipelines, including plastic gas transmission pipelines. The rule 
requires an operator to take additional measures beyond those already 
required in Part 192 to prevent a pipeline failure and to mitigate the 
consequences of a pipeline failure in a high consequence area. An 
operator must base the additional measures on the threats the operator 
has identified to each pipeline segment. (Threat identification is in 
Sec.  192.917.) The rule requires an operator to conduct, in accordance 
with one of the risk assessment approaches in Section 5 of ASME/ANSI 
B31.8S, a risk analysis of its pipeline to identify additional measures 
to protect the high consequence area and enhance public safety. 
Examples of additional measures listed in the rule are: installing 
Automatic Shut-off Valves or Remote Control Valves, installing 
computerized monitoring and leak detection systems, replacing pipe 
segments with pipe of heavier wall thickness, providing additional 
training to personnel on response procedures, conducting drills with 
local emergency responders and implementing additional inspection and 
maintenance programs. These are not the only measures an operator 
should consider or use.
    The rule requires an operator to enhance its current damage 
prevention program required under Sec.  192.614 with respect to a 
covered segment to prevent and minimize the consequences of a release 
due to third-party or outside force damage. The rule lists examples of 
enhanced damage prevention program measures. These are the minimum 
actions an operator can take to enhance its current program.
    [sbull] Using qualified personnel for work an operator is 
conducting that could adversely affect the integrity of a covered 
segment, such as marking, locating, and direct supervision of known 
excavation work.
    [sbull] Collecting in a central database information that is 
location specific on excavation damage that occurs in covered and non-
covered segments in the transmission system and the root cause analysis 
to support identification of targeted additional preventative and 
mitigative measures in the high consequence areas. This information 
must include recognized damage that is not required to be reported as 
an incident under Part 191.
    [sbull] Participating in one-call systems in locations where 
covered segments are present.
    [sbull] Monitoring of excavations conducted on covered pipeline 
segments by pipeline personnel. When there is physical evidence of 
encroachment involving excavation near a covered segment, an operator 
must either excavate the area near the encroachment or conduct an above 
ground survey using methods defined in NACE RP-0502-2002. An operator 
must excavate, and remediate, in accordance with ASME/ANSI B31.8S and 
Sec.  192.933 any indication of coating holidays or discontinuity 
warranting direct examination.
    If an operator determines that outside force, such as earth 
movement, floods, or an unstable suspension bridge, is a threat to the 
integrity of a covered segment, the rule requires the operator to take 
measures to minimize the consequences to covered segments from outside 
force damage. The minimum measures an operator can take are: increasing 
the frequency of aerial, foot or other methods of patrols, adding 
external protection, reducing external stress, and relocating the 
pipeline.
    The requirements for third-party damage and outside force damage 
also apply to plastic transmission pipelines.
    The rule allows that there may be limited instances in which an 
operator will determine that installing an automatic shut off or remote 
control valve is necessary. The rule provides that if an operator 
determines, based on a risk analysis, that such a valve would be an 
efficient means of adding protection to a high consequence area in the 
event of a gas release, an operator must install the valve. In making 
that determination, an operator must, at least, consider the swiftness 
of leak detection and pipe shutdown capabilities, the type of gas being 
transported, operating pressure, the rate of potential release, 
pipeline profile, the potential for ignition, and location of nearest 
response personnel.
    Because under the revised definition of a high consequence area, 
some low-stress pipelines may not be in a high consequence area, 
although the pipeline is in a populated area, the rule adds additional 
requirements for these pipelines. Thus, if a transmission pipeline 
operates below 30% SMYS and is located in a Class 3 or 4 area but not 
in a high consequence area, an operator must apply the enhanced third-
party damage prevention requirements for using qualified personnel and 
participating on one-call centers to the pipeline and either monitor 
excavations near the pipeline, or conduct patrols of the pipeline at 
bi-monthly intervals. If an operator finds any indication of unreported 
construction activity, the operator must conduct a follow up 
investigation to determine if mechanical damage has occurred.

Section 192.937 What Is a Continual Process of Evaluation and 
Assessment To Maintain a Pipeline's Integrity?

    After completing the baseline integrity assessment of a covered 
segment, the rule provides that an operator must continue to assess the 
line pipe of that segment at specified intervals (in Sec.  192.939) and 
to periodically evaluate the integrity of each covered pipeline 
segment. If an operator had used a prior assessment as the baseline 
assessment, the reassessment must be done by no later than December 17, 
2009. If a prior assessment is not used as the baseline, a reassessment 
of a covered segment must be done by no later than seven years after 
the baseline assessment of that covered segment unless the periodic 
evaluation indicates earlier reassessment.
    The rule requires a periodic evaluation as frequently as needed to

[[Page 69809]]

ensure the integrity of each covered segment. The periodic evaluation 
must be based on a data integration and risk assessment of the entire 
pipeline. The data integration and risk assessment requirements are in 
Sec.  192.917. For plastic transmission pipelines, the periodic 
evaluation is based on the threat analysis specified in Sec.  
192.917(d) considering the data on unique threats to a plastic 
pipeline. For all other transmission pipelines, the evaluation must 
consider the past and present integrity assessment results, data 
integration and risk assessment information, and decisions about 
remediation (Sec.  192.933) and additional preventive and mitigative 
actions (Sec.  192.935). An operator must use the results from this 
evaluation to identify the threats specific to each covered segment and 
the risk represented by these threats.
    The rule allows several assessment methods for a reassessment. In 
conducting the integrity reassessment, an operator must assess the 
integrity of the line pipe in the covered segment by any of the 
following methods as appropriate for the threats to which the covered 
segment is susceptible (see Sec.  192.917), or by confirmatory direct 
assessment under the conditions specified in Sec.  192.931. The methods 
allowed for reassessment are--
    [sbull] Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the covered segment is 
susceptible. An operator must follow Section 6.2 of ASME/ANSI B31.8S in 
selecting the appropriate internal inspection tools for the covered 
segment.
    [sbull] Pressure test conducted in accordance with Subpart J;
    [sbull] Direct assessment to address threats of external corrosion 
and internal corrosion or stress corrosion cracking. An operator must 
conduct the direct assessment in accordance with the requirements 
listed in Sec.  192.923 and with as applicable, the requirements 
specified in Sec. Sec.  192.925 (external corrosion), 192.927 (internal 
corrosion) or 192.929 (stress corrosion cracking);
    [sbull] Other technology that an 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) 180 days before conducting the assessment.
    [sbull] Confirmatory direct assessment when used on a covered 
segment that is scheduled for reassessment at a period longer than 
seven years. An operator using this reassessment method must comply 
with Sec.  192.931.

Section 192.939 What Are the Required Reassessment Intervals?

    The required reassessment interval depends on the assessment method 
and the operating pressure of the pipeline. Some form of reassessment 
must be done at least every seven years.
    For pipelines operating at or above 30% SMYS, the rule allows 
reassessment by--
    1. Pressure test or internal inspection, or other equivalent 
technology. An operator that uses pressure testing or internal 
inspection as an assessment method must establish the reassessment 
interval for a covered pipeline segment by--
    [sbull] Basing the intervals on the identified threats for the 
segment as listed in Sec.  192.915 of this section and in Section 8, 
Tables 6 and 7 of ASME/ANSI B31.8S, and on the analysis of the results 
from the last integrity assessment and from the data integration and 
risk assessment required by Sec.  192.911; or
    [sbull] Using the intervals for different stress levels of pipeline 
specified in Table 3, Section 5 of ASME/ANSI B31.8S.
    2. External Corrosion Direct assessment. An operator that uses 
external corrosion direct assessment must determine the reassessment 
interval according to the requirements in paragraphs 6.2 and 6.3 of 
NACE RP0502-2002.
    3. Internal Corrosion or SCC Direct Assessment. An operator that 
uses ICDA or SCCDA must determine the reassessment interval by 
determining the largest defect most likely to remain in the covered 
segment and the corrosion rate appropriate for the pipe, soil and 
protection conditions, taking the largest remaining defect as the size 
of the largest defect discovered in the SCC or ICDA segment and 
estimating the reassessment interval as half the time required for the 
largest defect to grow to a critical size. However, the reassessment 
interval cannot exceed those specified for direct assessment in Table 
3, Section 5 of ASME/ANSI B31.8S.
    If using one of these allowable methods, an operator establishes a 
reassessment interval that is greater than seven years, the operator 
must within the seven-year period, conduct a confirmatory direct 
assessment on the covered segment, and then conduct the follow-up 
reassessment at the interval the operator has established. A 
reassessment done by confirmatory direct assessment must follow the 
requirements in Sec.  192.931.
    For pipelines operating below 30% SMYS the rule allows reassessment 
by--
    1. Pressure test, internal inspection or other equivalent 
technology following the requirements for pipelines operating above 30% 
SMYS, except that the stress level would be adjusted to reflect the low 
operating stress level. If an established interval is more than seven 
years, the operator must conduct by the seventh year of the interval 
either a confirmatory direct assessment in accordance with Sec.  
192.931, or a low-stress reassessment in accordance with Sec.  192.941.
    2. External Corrosion Direct assessment following the requirements 
described for pipelines operating above 30% SMYS.
    3. Internal Corrosion or SCC Direct Assessment following the 
requirements described for higher stress pipelines.
    4. Confirmatory direct assessment at seven-year intervals in 
accordance with Sec.  192.931, with reassessment by one of the other 
allowed methods (pressure test, internal inspection or direct 
assessment) by year 20 of the interval.
    5. Low-stress assessment method at seven-year intervals in 
accordance with Sec.  192.941 with reassessment by one of the other 
allowed methods (pressure test, internal inspection or direct 
assessment) by year 20 of the interval.

Section 192.941 What Is a Low-Stress Reassessment?

    The rule provides for a low-stress reassessment for transmission 
pipelines that operate below 30% SMYS. This reassessment addresses the 
threats that are more common to these low-stress pipelines. The low-
stress method only applies to a reassessment.
    To address the threat of external corrosion on cathodically 
protected pipe in a covered segment, an operator must--
    [sbull] Perform an electrical survey (i.e., indirect examination 
tool/method) at least every seven years on the covered segment.
    [sbull] Use the results of each survey as part of an overall 
evaluation of the cathodic protection and corrosion threat for the 
covered segment. This evaluation must consider, at minimum, the leak 
repair and inspection records, corrosion monitoring records, exposed 
pipe inspection records, and the pipeline environment.
    If an electrical survey is impractical on the covered segment an 
operator must instead
    [sbull] Conduct leakage surveys at 4-month intervals; and
    [sbull] Every 1\1/2\ years, identify and remediate areas of active 
corrosion by evaluating leak repair and inspection records, corrosion 
monitoring records,

[[Page 69810]]

exposed pipe inspection records, and the pipeline environment.
    To address the threat of internal corrosion on a covered segment, 
an operator must--
    [sbull] Conduct a gas analysis for corrosive agents at least once 
each calendar year;
    [sbull] Conduct periodic testing of fluids removed from the 
segment. At least once each calendar year test the fluids removed from 
each storage field that may affect a covered segment; and
    [sbull] At least every seven years, integrate data from this 
analysis and testing with applicable internal corrosion leak records, 
incident reports, safety-related condition reports, repair records, 
patrol records, exposed pipe reports, and test records, and define and 
implement appropriate remediation actions.

Section 192.943 When Can an Operator Deviate From These Reassessment 
Intervals?

    The rule provides for a waiver from the reassessment intervals in 
two limited instances. In either instance the waiver has to be done in 
accordance with 49 U.S.C. 60118(c), which requires public notice and 
comment, and OPS has to find that the waiver would not be inconsistent 
with pipeline safety. The rule requires an operator to apply for a 
waiver at least 180 days before the end of the required reassessment 
interval, unless local product supply issues make that period 
impractical. The two instances when an operator may apply for a waiver 
are--
    1. Lack of internal inspection tools.
    In this instance an operator who uses internal inspection as an 
assessment method may be able to justify a longer assessment period for 
a covered segment if internal inspection tools are not available to 
assess the line pipe. To justify this, the operator must demonstrate 
that it cannot obtain the internal inspection tools within the required 
assessment period and that the actions the operator is taking in the 
interim ensure the integrity of the covered segment.
    2. To maintain product supply.
    An operator may be able to justify a longer reassessment period for 
a covered segment if the operator demonstrates that it cannot maintain 
local product supply if it conducts the reassessment within the 
required interval.

Section 192.945 What Methods Must an Operator Use To Measure Program 
Effectiveness?

    The rule requires an operator have performance measures to measure, 
on a semi-annual basis, whether the program is effective in assessing 
and evaluating the integrity of each pipeline segment and in protecting 
the HCAs. These measures must include the four overall performance 
measures specified in Section 9.4 of ASME/ANSI B31.8S and the specific 
measures for each identified threat specified in Appendix A of ASME/
ANSI B31.8S. An operator must submit the four overall performance 
measures electronically on a semi-annual frequency to OPS.
    In addition to the general requirements for performance measures 
the rule requires that if an operator uses direct assessment to assess 
the external corrosion threat, the operator must also must define and 
monitor measures to determine the effectiveness of the ECDA process. 
These measures must meet the external corrosion direct assessment 
requirements in Sec.  192.925.

Section 192.947 What Records Must an Operator Keep?

    The rule provides that an operator must maintain, for the useful 
life of the pipeline, records that demonstrate compliance with the 
requirements of the integrity management program rule. This section 
lists the minimum records an operator has to maintain for review during 
an inspection.

Section 192.949 How Does an Operator Notify OPS?

    For any of the required notification, the rule allows an operator 
to submit the notification by one of three methods.
    [sbull] Sending the notification by mail to the Information 
Resources Manager, Office of Pipeline Safety, Research and Special 
Programs Administration, U.S. Department of Transportation, Room 7128, 
400 Seventh Street, SW, Washington DC 20590;
    [sbull] Sending the notification by facsimile to (202) 366-7128; or
    [sbull] Entering the information directly on the Integrity 
Management Database (IMDB) Web site at http://primis.rspa.dot.gov/gasimp/.

Section 192.951 Where Does an Operator File a Report?

    The rule has certain reporting requirements. An operator must send 
these reports to OPS by one of three methods.
    [sbull] By mail to the Office of Pipeline Safety, Research and 
Special Programs Administration, U.S. Department of Transportation, 
Room 7128, 400 Seventh Street, SW, Washington, DC 20590;
    [sbull] Via facsimile to (202) 366-7128; or
    [sbull] Through the online reporting system provided by OPS for 
electronic reporting available at the OPS Home Page at http://ops.dot.gov.
    This rule also adds a new Appendix E to Part 192, Guidance on 
Determining High Consequence Areas, and on carrying out requirements in 
the Integrity Management Rule. The guidance in the appendix describes 
the process an operator must use to determine whether a pipeline 
segment is in a high consequence area.
    The new Appendix also provides guidance on alternative assessment 
methods for transmission pipeline operating at below 30% SMYS. That 
guidance is provided in the form of three tables:
--Table E.II.1 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats, for transmission pipelines operating below 30% 
SMYS not in HCAs (i.e., outside of Potential Impact Circles) but 
located within Class 3 and 4 locations.
--Table E.II.2 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats, for transmission pipelines operating below 30% 
SMYS in HCAs.
--Table E.II.3 gives guidance on preventative & mitigative measures 
addressing time dependent and independent threats for transmission 
pipelines that operate below 30% SMYS, in HCAs.

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) because of its significant public and government interest.
    A regulatory evaluation of this final rule on Integrity Management 
for gas transmission pipelines has been prepared and placed in the 
docket.

Cost-Benefit Analysis

    A copy of the final regulatory evaluation has been placed in the 
docket for this final rule. The following section summarizes the 
regulatory evaluation's findings.
    Natural and other gas pipeline ruptures can adversely affect human 
health and property. However, the magnitude of this impact differs from 
area to area. There are some areas in

[[Page 69811]]

which the impact of an accident will be more significant than it would 
be in others due to greater concentrations of people who could be 
affected. Because of the potential for dire consequences of pipeline 
failures in certain areas, these areas merit a higher level of 
protection. RSPA/OPS is requiring this regulation to afford the 
necessary additional protection to these HCAs.
    Numerous investigations by RSPA/OPS and NTSB have highlighted the 
importance of protecting the public from pipeline failures. NTSB has 
made several recommendations to ensure the integrity of pipelines near 
populated 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 pipelines to 
provide for rapid shutdown of failed pipelines.
    Congress also directed RSPA/OPS to undertake additional safety 
measures in areas that are densely populated. These statutory 
requirements included having RSPA/OPS prescribe standards for 
identifying pipelines in high density population areas and issue 
standards requiring periodic inspections. The Pipeline Safety 
Improvement Act of 2002 requires that RSPA/OPS adopt regulations 
requiring operators of gas transmission pipelines in HCAs to adopt 
integrity management plans.
    This final rulemaking addresses the target problem described above, 
and is a comprehensive approach to certain NTSB recommendations and 
Congressional mandates, as well as pipeline safety and environmental 
issues raised over the years.
    This final rule focuses on a systematic approach to integrity 
management to reduce the potential for natural and other gas 
transmission pipeline failures that could affect populated areas. This 
final rulemaking requires pipeline operators to develop and follow an 
integrity management program that continually assesses, through 
internal inspection, pressure testing, direct assessment or equivalent 
alternative technology, the integrity of those pipeline segments that 
could affect areas we have defined as HCAs, i.e., areas with specified 
population densities, buildings containing populations of limited 
mobility, and areas where people gather, that occur along the route of 
the pipeline. 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 fourth in a series of integrity management 
program regulations) covers operators of transmission pipelines for 
natural and other gases. RSPA/OPS chose to start the series with 
hazardous liquid pipeline operators because the pipelines they operate 
have the greatest potential to adversely affect the environment. This 
final rule completes the application of integrity management to all 
interstate (and many intrastate) pipelines.

Benefits

    RSPA/OPS has made significant changes to the cost-benefit analysis 
since the analysis prepared to support the proposed rule. Included in 
these changes is full consideration of the impact of the Pipeline 
Safety Improvement Act of 2002. The Act significantly changed the 
regulatory environment in which the new rule will be implemented. The 
Act requires that gas transmission pipeline operators develop integrity 
management plans, perform risk analyses, and perform certain tests, 
including tests at specified intervals. These requirements forever 
change the regulatory landscape. The notice of proposed rulemaking was 
issued in January, only one month after the Act was signed into law. 
RSPA/OPS modified the notice to acknowledge that the law was passed and 
that it imposed some requirements, but RSPA/OPS had not taken time to 
analyze thoroughly the impacts the Act would have.
    RSPA/OPS has since performed extensive analyses to consider the 
impacts of the Act and to evaluate ways to make the rule more cost-
beneficial. RSPA/OPS has estimated the costs to implement the 
requirements in the Act, without modification, to be approximately $11 
billion over 20 years. By comparison, we conclude the cost of 
implementing this rule will be $4.7 billion over the same period. The 
difference reflects changes made in this rule in the definition of HCAs 
(which will have the effect of reducing the amount of pipeline mileage 
that must be tested) and provisions for limited scope reassessments 
every seven years. The Act requires that pipelines be assessed every 
seven years. The Act further requires that these assessments be 
performed using one of three specified assessment methods or ``an 
alternative method that the Secretary [of Transportation] determines 
would provide an equal or greater level of safety.'' The alternative 
methods included in this rule will reduce costs significantly over the 
cost of performing periodic assessments using only the methods 
specified in the Act. There is therefore a benefit in adopting this 
rule of approximately $6.2 billion in cost reduction for assuring 
pipeline integrity.
    Benefits will also accrue in improved ability to site pipelines in 
certain critical markets. It is difficult to quantify this benefit, but 
RSPA/OPS believes it is real. Inability to site future pipelines could 
affect the Nation's ability to use the increased quantities of natural 
gas that the Energy Information Administration estimates will be needed 
to fuel our economy over the next 20 years.
    The Energy Information Administration (EIA), in its Annual Energy 
Outlook 2003, estimates that total consumption of natural gas in the 
United States was 22.64 trillion cubic feet in 2001. EIA's Outlook 
projects, in its reference case, that this figure will grow to 32.14 
trillion cubic feet by 2020. The EIA projection is for consumption of 
34.59 trillion cubic feet by 2020 for its high economic growth 
scenario. These figures represent an increase of 42 and 53 percent from 
total 2001 consumption. Additional transmission pipeline capacity is 
likely to be needed to support these estimates, and to deliver the gas 
that the American economy will need in 2020. The increased public 
confidence in pipeline safety that will result from this rule will make 
it easier to site and construct this additional pipeline capacity. The 
ability to build to support the need of the U.S. economy is a principal 
benefit of this rule.
    The rule will significantly reduce the likelihood of pipeline 
accidents that result in deaths and serious injuries. Based on the 
historical record, RSPA/OPS has estimated this benefit to be on the 
order of $800 million over 20 years. It is quite likely, though, that 
future accidents could be worse than the historical experience. 
Population near pipelines is growing. This places more people at risk 
than in the past. While some historical accidents have resulted in 
several deaths and serious injuries, and significant property damage, 
accidents with even greater consequences could occur. RSPA/OPS has 
analyzed the likelihood that an accident could occur in an area along 
the pipeline that is more densely populated. Even though the amount of 
pipeline mileage along which such high population densities might be 
found is small (RSPA/OPS estimated 0.1% of total mileage for this 
analysis) the consequences of an accident are potentially large enough 
that the averted costs are still high. RSPA/OPS estimates

[[Page 69812]]

that an additional $277 million is realized by avoiding the likelihood 
of this more significant accident.
    The rule will also result in avoiding significant costs associated 
with unexpected interruptions in natural gas supply. The 2000 Carlsbad 
accident resulted in curtailment of supply of natural gas to 
California. RSPA/OPS estimates that this resulted in an impact on the 
California economy of $17.25 million per day. The total benefit 
afforded by this rule in avoiding future economic impacts of this type 
is estimated to be $1 billion over the next 20 years.
    Another benefit to be realized from implementing this rule is 
reduced cost to the pipeline industry for assuring safety in areas 
along pipelines with relatively more population. The improved knowledge 
of pipeline integrity that will result from implementing this rule will 
provide a technical basis for providing relief to operators from 
current requirements to reduce operating stresses in pipelines when 
population near them increases. Regulations currently require that 
pipelines with higher local population density operate at lower 
pressures. This is intended to provide an extra safety margin in those 
areas. Operators typically replace pipeline when population increases, 
because reducing pressure to reduce stresses reduces the ability of the 
pipeline to carry gas. Areas with population growth typically require 
more, not less, gas. Replacing pipeline, however, is very costly. 
Providing safety assurance in another manner, such as by implementing 
this rule, could allow RSPA/OPS to waive some pipe replacement. RSPA/
OPS estimates that such waivers could result in a reduction in costs to 
industry of $1 billion over the next 20 years, with no reduction in 
public safety.

Costs

    Comments submitted in response to the draft regulatory analysis 
pointed out that the costs to do much work associated with pipeline 
integrity assessments, e.g., excavating pipe for direct examination, 
are much higher in urban areas than they are in rural locations. The 
comments suggested that use of a single set of unit costs (i.e., costs 
per-mile) to represent all pipeline was unreasonable. RSPA/OPS accepts 
that work in urban areas is more costly. In the final regulatory 
analysis, RSPA/OPS has used different unit costs for work on long-
distance pipelines, traversing largely rural areas, and for shorter 
transmission pipelines owned by gas distribution companies, which are 
generally in urban areas. RSPA/OPS has relied on comments submitted by 
INGAA, whose members consist of operators of long-distance pipelines, 
and the American Gas Association (AGA) and American Public Gas 
Association (APGA), whose members are gas distribution companies, for 
the unit costs used in the final regulatory analysis.
    RSPA/OPS analyzed two scenarios in the draft regulatory analysis, 
varying the amount of pipeline that operators are expected to modify to 
accommodate in-line inspection. This approach was taken, because of 
industry comments that significant amounts of pipeline would likely be 
modified and the costs for that work. Some pipe already can accommodate 
in-line inspection tools. Some can be modified to accommodate the in-
line inspection tools with relatively simple modifications. Others 
require much more extensive retrofits. RSPA/OPS was uncertain whether 
operators would incur the significant costs to modify this ``hard-to-
pig'' pipeline or, instead, rely on direct assessment for those 
pipeline segments. One of the analyzed scenarios assumed that only the 
piping that can easily be modified would be changed. The other scenario 
was based on the assumption that a portion of the pipe requiring more 
extensive changes would also be modified.
    Comments submitted in response to the draft regulatory analysis 
strongly supported the premise that operators will modify much hard-to-
pig pipeline. Discussions at public meetings and at the Technical 
Pipeline Safety Standards Committee indicated a strong preference for 
pigging, and a full intent, on the part of the industry, to pursue that 
approach in most cases. This is, in part, because pigging provides an 
operator with much more information about the pipeline. Faced with 
these comments, RSPA/OPS believes it would be unreasonable to continue 
to analyze a scenario in which no hard-to-pig pipe is changed. As 
demonstrated by the two scenarios considered in the draft regulatory 
analysis, costs are much higher during the baseline assessment period 
when hard-to-pig pipe is assumed to be modified.
    Initial experience with direct assessment, however, indicates 
higher costs for using this method than originally estimated, making 
reassessment costs lower if a larger proportion of affected pipeline is 
pigged. This adds an economic incentive to modify pipeline for pigging 
and further supports eliminating the ``Limited Modification'' scenario.
    We have estimated the cost for operators to identify pipeline 
segments that can affect HCAs at approximately $15.05 million, the cost 
to develop the necessary programs at approximately $104.13 million and 
an annual cost for program upkeep and reporting of $12.91 million. 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 be made to implement each element. As 
decisions are made and operators evaluate the effectiveness of the 
program in protecting HCAs, the program will be updated and improved, 
as needed.
    The final rule requires a baseline assessment of covered pipeline 
segments through internal inspection, pressure test, direct assessment 
or use of other technology capable of equivalent performance. The 
baseline assessment must be completed within ten years after December 
17, 2002 (the date the Pipeline Safety Improvement Act of 2002 was 
signed into law), with at least 50% of covered segments being assessed 
within five years.
    After this baseline assessment, the rule further requires that an 
operator periodically reassess and evaluate the pipeline segment to 
ensure its integrity. The interval in which reassessments must be 
performed varies with the operating stress levels in the pipe. 
Pipelines operating at greater than 50 percent of specified minimum 
yield strength (SMYS) must be reassessed at least every 10 years. 
Pipelines operating between 30 and 50 percent SMYS must be reassessed 
every fifteen-years. Pipelines operating below 30 percent SMYS require 
reassessment on a twenty-year interval.
    RSPA/OPS believes that the higher the operating pressure of a 
pipeline, the greater the potential risk the pipeline poses to the 
general public. That is because a failure of a pipeline operating at a 
higher pressure will result in a larger impact area and potentially 
more significant consequences. It is under this assumption that RSPA/
OPS has established the shortest assessments intervals for pipelines 
that operate at or above pressures of 50 percent of SMYS. By basing the 
assessment interval according to pipeline pressure, operators will have 
to focus their safety resources on pipelines that pose the greatest 
danger. RSPA/OPS believes that varying the assessment interval 
according to the risk provides the greatest safety reward per dollar 
operators will expend.
    The Pipeline Safety Improvement Act of 2002 requires reassessment 
of all pipelines in HCAs every seven years. To meet this requirement an 
operator must conduct some assessment at that

[[Page 69813]]

frequency. The final rule provides a means to fulfill this requirement 
at reduced burden, and lower financial impact. If an operator takes 
advantage of the longer reassessment intervals provided in this final 
rule, the rule requires that the operator conduct an interim 
reassessment at least every seven years using a more focused direct 
assessment (Confirmatory Direct Assessment) method.
    Confirmatory direct assessment is a more focused application of the 
principles and techniques of direct assessment, that is concentrated on 
identifying critical segments of suspected corrosion and third-party 
damage. RSPA/OPS has structured the requirements for confirmatory 
direct assessment in a manner intended to allow maximum flexibility for 
operators. Indirect examinations may be performed using only one, 
rather than two, tools. Corrosion regions may be larger than for 
regular direct assessments. The number of excavations required per 
region is less. These changes will allow operators to plan and conduct 
confirmatory direct assessments in a manner that is most cost-
effective, i.e., identifies areas of concern at lowest cost.
    RSPA/OPS estimates that the cost of periodic reassessment will 
generally not occur until the eighth year, unless the baseline 
assessment indicates significant defects that would require earlier 
reassessment. Operators must begin CDA interim assessments in the 
eighth year. Additionally, some operators of higher-pressure pipelines, 
who must perform regular reassessments in ten years, may elect to 
perform those assessments at seven-year intervals instead of using CDA. 
The cost-benefit analysis assumes that half of the affected pipeline 
operating above 50 percent SMYS will be assessed using the higher-cost 
methods every seven years.
    The analysis of costs RSPA/OPS expects operators to incur in 
implementing the rule results in an estimated annual cost of $262.1 
million to conduct baseline testing. This includes the cost to modify 
pipelines. All necessary modifications will be completed during the 
baseline period, making annual costs for reassessments considerably 
lower. Our analysis estimates that annual reassessment costs will be 
approximately $50 million, varying slightly in different years 
depending on which pipeline is due for reassessment.
    Integrating information related to the pipeline's integrity is a 
key element of the integrity management program. Costs will be incurred 
to recover historical data about the pipeline and incorporate it in 
modern data management systems that will allow it to be used more 
readily. RSPA/OPS estimates that most of these costs will be incurred 
in the first year after the effective date of the rule. Operators will 
incur annual costs thereafter to incorporate new data, including the 
results from assessments, and for integration and analysis by 
knowledgeable pipeline safety professionals. RSPA/OPS estimated in the 
draft regulatory analysis that the total costs for the information 
integration requirements would be $31.5 million in the first year and 
$15.75 million annually thereafter. Comments indicated that these 
estimates, particularly for the first year, were very low. The 
Interstate Natural Gas Association of America (INGAA) pointed out that 
costs to gather old data, much of which is in paper records and not 
easily retrieved, would be much higher. INGAA estimated that operators 
would incur costs of $1,359 per mile for the initial data gathering and 
setup and $113 per mile for annual updates and analysis. RSPA/OPS 
accepts that costs to retrieve old data will be high, and that 
estimating these costs on a per-mile basis is reasonable. RSPA/OPS has 
adopted the INGAA-provided unit costs. Applying them results in an 
estimated total cost for data integration of $387.3 million in the 
first year and $32.21 million annually thereafter.
    The final rule also requires operators to evaluate the risk of 
pipeline segments that can affect HCAs to determine if additional 
preventive or mitigative measures that would enhance public safety 
should be implemented. One of the additional preventive or mitigative 
actions that an operator can take is to install automatic shutoff 
valves or remotely controlled valves. RSPA/OPS could not estimate the 
total cost of installing such valves in response to this rule, because 
there are too many factors that would have to be analyzed in order to 
produce a valid estimate of how many operators will install them. RSPA/
OPS completed a generic study in 1999, however, in which we concluded 
that conversion of existing sectional block valves to remote operation 
was not economically feasible in most cases. Operator- and location-
specific factors could change this conclusion for individual valves but 
RSPA/OPS could not analyze these specific factors for individual block 
valves and therefore, did not estimate the total cost for installing 
remote valves. RSPA/OPS presumes that operators will analyze valve-
specific factors and will not replace valves unless that action is 
cost-beneficial. RSPA/OPS estimates that the cost to operators to 
perform the required risk analyses will be approximately $11.5 million.

Consideration by Advisory Committee

    RSPA/OPS discussed the final regulatory analysis with the Technical 
Pipeline Safety Standards Committee (TPSSC) in a public teleconference 
on July 31, 2003. The TPSSC, composed equally of representatives of 
industry, government, and groups representative of public involvement 
in pipeline safety issues, agreed that the analysis provides a basis to 
justify proceeding with this rulemaking. The committee unanimously 
concluded that the expected benefit in terms of improved public 
confidence in pipeline safety is substantial and justifies the expected 
costs.

Conclusions

    RSPA/OPS concludes that the benefits are about the same as the 
costs. Quantified benefits total $4.7 billion over the 20 years 
analyzed. Costs over this same period are estimated to be $4.7 billion. 
There are additional benefits for which it was difficult to estimate 
monetary values. These include an improved basis for public confidence 
in pipeline safety, with attendant improvements in the ability to site 
new pipelines; reduced consequential damages from an unexpected 
interruption of gas service, providing a technical basis that will 
allow increases in pressure, and thus in delivery of gas, during future 
energy emergencies; and providing incentives to foster additional 
improvements in pipeline testing technology.
    The estimated costs for implementing this rule are significant. 
They need to be considered in the context of the size of the overall 
U.S. market for natural gas. Energy Information Administration figures 
show that total U.S. consumption of natural gas in 2001 amounted to 
20,477,009 million cubic feet. Residential consumption was 4,716,186 
million cubic feet. When the total estimated first-year costs for 
implementing this rule are divided over these quantities, they result 
in an increase in cost of 3.6 cents per thousand cubic feet. An average 
residential consumer would see an increase of $3.07 per year if these 
costs were passed on. This would mean an increase of 26 cents on an 
average monthly bill, or a 0.39 percent rise.
    RSPA/OPS considers these costs reasonable to realize the benefits 
associated with this rule. Additionally, promulgating this rule will 
result in savings of approximately $6.2 billion

[[Page 69814]]

over the expected costs to industry of complying with legislative 
requirements absent this rule. Publishing this final rule, and 
requiring that gas transmission pipeline operators comply, is clearly 
the appropriate course of action.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act, 5 U.S.C. 601 et seq., RSPA/
OPS must consider whether this rulemaking would have a significant 
impact on a substantial number of small entities. RSPA/OPS in its draft 
regulatory analysis used an estimate of 668 gas transmission operators 
that could potentially be impacted by the gas integrity management 
proposed rule. For the final regulatory evaluation RSPA/OPS performed 
an extensive computer search of gas transmission operators and found 
that many operators were in fact subsidiaries of large gas transmission 
companies and that there are 275 gas transmission operators that could 
potentially be impacted by this final rulemaking. A pipeline company 
would be impacted if its pipeline could affect a high consequence area 
(HCA). HCA's are located primarily urban areas but include rural areas 
where more than 20 people congregate.
    Of these 275 companies, approximately 35 could be considered small 
companies. About 25 of these are municipally operated gas distribution 
companies who also operate a transmission pipeline. The Small Business 
Administration (SBA) had concerns with the regulatory flexibility 
certification performed for the proposed gas integrity management 
regulation. In discussions with SBA OPS suggested that it would contact 
the American Public Gas Association (APGA) which is the trade 
organization which represents municipal gas distribution companies 
which make up the majority of the small entities among gas pipeline 
operators. OPS has asked that APGA help to disseminate information on 
rulemakings that could impact small pipeline operators. APGA has agreed 
to perform this function. While OPS has in the past solicited comments 
from small pipeline operators concerning potential impacts of pipeline 
safety regulations few if any small pipeline operators have ever 
submitted comments.
    The Interstate Natural Gas Association of America (INGAA) estimates 
that its members account for 80% of the gas pipeline transmission 
mileage in the United States. INGAA has only 24 members however, 3 of 
these members are not U.S. gas transmission operators. Therefore, 
approximately 21 companies account for 80% of the U.S. gas transmission 
pipeline mileage. The remainder of the pipeline companies in this 
industry share only 20% of the total pipeline mileage.
    The majority of the remaining 20% of transmission pipelines belong 
to large gas distribution companies and large industrial companies. The 
approximately 35 small entities own and operate very little mileage. 
Because they operate such little mileage (in most cases less than 30 
miles of pipeline), the compliance costs to these small entities if 
they are impacted by this rule will be significantly lower than those 
operators thousands of miles of pipeline as the costs of inspection and 
planning should be considerably lower. Specifically, OPS has estimated 
that the program planning and paperwork costs to operators with 30 
miles or less of pipeline will be considerably less than for long 
distance pipeline operators. If a small pipeline operator has for 
example only 30 miles of pipeline it is likely that they will have only 
a few miles of pipeline that will fall under this rule. If they choose 
to perform direct assessment which the APGA has said is the likely 
choice of their members the cost to inspect this will likely fall under 
$100,000. On the other hand a large transmission operator performing 
internal inspection on more than a thousand miles of pipeline is likely 
to cost that operator several million dollars. RSPA/OPS believes that 
this rule does not unduly burden small entities. Nevertheless, RSPA/OPS 
stands ready to provide special help to any small operators to assist 
them in complying with this final rule. Conversations with some small 
transmission companies indicates that state pipeline offices have been 
particularly effective in assisting small entities. Based on the above 
discussion I certify that this final rule will not have a significant 
impact on a substantial number of small entities.

Paperwork Reduction Act

    This final 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 HCAs Gas Transmission Pipeline Operators. OMB Control 
Number 2137-0610'' The purpose of this information collection is 
designed to require operators of gas transmission pipelines to develop 
a program to provide direct integrity testing and evaluation of gas 
transmission pipelines in HCAs.
    The following is a summary of the highlights of the paperwork 
reduction act analysis. The complete analysis can be found in the 
public docket. The costs and hour burden is based on 275 companies with 
a loaded labor cost of $60 per hour.
    In the first year of promulgating this rule operators will have to 
identify which segments are in HCAs. This will take 167 hours per 
company plus 5 hours per impact circle. Impact circle is a measure of 
how wide the HCAs will be. The total hours for the entire industry will 
be 25,083 hours in the first year only.
    The development of the integrity management plan will take 8333 
hours for an operator with more than 30 miles of pipelines and 2,083 
for operators with less than 30 miles of pipeline in the first year. 
The time to update the plans annually will be 833 hours for operators 
with more than 30 miles and 417 for operators with less than 30 miles.
    The one time requirement to examine the need for remotely 
controlled valves is estimated to take operators with more than 30 
miles of pipeline 833 hours and 417 hours for operators with less than 
30 miles of pipeline.
    Additionally, all the operators will be required to integrate the 
new data they collect into their current management systems. The time 
to integrate the data the first year will be 22\1/3\ hours per mile and 
1.9 hours per mile annually thereafter.
    Additional paperwork and recordkeeping beyond those already 
discussed, will add 833 hours in the first year for companies with more 
than 30 miles of pipeline and 417 hours for operators with less than 30 
miles of pipeline. In subsequent years this should add 83 hours of 
paperwork burden for all operators.
    The total initial time to perform all paperwork is 8,818,500 
million hours at a cost of $529.1 million. The subsequent annual time 
to update the paperwork is 752,000 hours costing $45.1 million dollars. 
Comments concerning this information collection should include the 
docket number of this rule. They should be sent within 30 days of the 
publication of this notice directly to the Office of Management and 
Budget, Office of Information and Regulatory Affairs, 726 Jackson 
Place, NW., Washington, DC 20503, ATTN: Desk Officer for the Department 
of Transportation (DOT).
    Comments are specifically requested concerning:
    [sbull] Whether the collection is necessary for the proper 
performance of the functions of the Department, including

[[Page 69815]]

whether the information would have a practical use;
    [sbull] The accuracy of the Department's estimate of the burden of 
collection of information including the validity of assumptions used;
    [sbull] 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 details see, the complete 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 have any requirement 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, 1999) do not apply. Nevertheless, 
in November 18-19, 1999, and in February 12-14, 2001 public meetings, 
RSPA/OPS invited National Association of Pipeline Safety 
Representatives (NAPSR), which includes State pipeline safety 
regulators, to participate in a general discussion on pipeline 
integrity. Since then, RSPA/OPS has held conference calls with NAPSR, 
to receive their input before proposing an HCA definition and integrity 
management rule. RSPA/OPS has invited NAPSR representatives to all the 
public meetings held subsequent to the publication of the pipeline 
integrity management NPRM.

Executive Order 13211

    This rulemaking is not a ``significant energy action'' within the 
meaning of Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use''). It is a 
significant regulatory action under Executive Order 12866 because of 
its significant public and government interest. As concluded from our 
Energy Impact Statement discussed in the following section, the 
rulemaking is not likely to have a significant adverse effect on the 
supply, distribution, or use of energy. Further, this rulemaking has 
not been designated by the Administrator of the Office of Information 
and Regulatory Affairs as a significant energy action.

Summary of the Energy Impact Statement

(For the detailed Energy Impact Statement, refer to Docket RSPA-00-
7666)

    The Research and Special Program Administration's Office of 
Pipeline Safety (RSPA/OPS) is currently promulgating regulations to 
assess, evaluate, remediate, and validate the integrity of natural gas 
transmission pipelines through comprehensive analysis and inspection of 
pipeline systems. The current rule applies to all gas transmission 
pipelines, including pipelines transporting petroleum gas, hydrogen, 
and other gas products covered under 49 CFR Part 192.
    In compliance with the Executive Order 13211 (66 FR 28355), the 
RSPA/OPS has evaluated the effects of the natural gas IMP rule on 
energy supply, distribution, or use. The RSPA/OPS has determined that 
this regulatory action would not have significant adverse effects on 
energy supply, distribution, or use nationally, however there may be 
some regional effect on natural gas distribution.
    The current rule will not have any significant impact on the 
wellhead production capacity or prices. The rule affects natural gas 
transmission pipelines in HCAs and has no effect on the wellhead 
production capacity or prices. The rule does not impact gas gathering 
pipelines and offshore gas transmission pipelines, and has limited 
effect on the onshore gas transmission lines that are not located in 
the HCAs. Therefore, the rule will have no significant impact on 
natural gas production or wellhead prices. The RSPA/OPS estimates that 
about 22,000 miles of gas transmission pipelines are located in the 
HCAs in a network of 300,000 miles of gas transmission pipelines, as 
well as 900,000 miles of gas distribution pipelines. Therefore, a 
relatively small proportion of pipelines, less than 1 percent of the 
total gas transmission pipelines, are located in the HCAs.
    This rule may affect the movement of natural gas in certain areas 
during integrity inspection. Inspection requirements may temporarily 
affect transportation capacity in some pipelines, but not in all 
pipelines. Built-in redundancies, such as loop lines, multiple lines, 
storage facilities, are part of natural gas transportation 
infrastructures. The intricate interconnections between pipelines, the 
availability of storage at the market centers, and a well-developed 
capacity release market all contribute towards meeting natural gas 
demand with efficient movement of supply. Therefore, inspections can be 
conducted without any significant disruption of throughput especially 
during off-peak seasons.
    This rule may not have any significant price effects on end-use 
consumers. In general, inter-fuel competition and gas-storage 
availability play significant roles in short-term price determination 
in U.S. because of extensive fuel switching capability in industry and 
power generation and the existence of a sizable storage capacity. 
Weather is the other significant player determining the spot market 
prices. Transportation cost only accounts for a small proportion of the 
cost paid by the end-users. The pipeline capacity reduction due to the 
integrity rule would be pre-planned and the market would have time to 
adjust for the reduction, minimizing shortages and avoiding short-term 
price increases. The RSPA/OPS recognizes that there may be some 
temporary and regional natural gas price impact due to the increased 
assessment and inspection requirements of the rule. While RSPA/OPS did 
not estimate the size of such temporary impacts, it could lead to small 
changes in natural gas prices for certain areas on the spot market if 
the inspection coincides with peak season and there is no other 
pipeline (no parallel, lateral, or loop lines) serving that particular 
area. Recognizing the possibility of temporary spot price fluctuations 
at the regional level, RSPA/OPS believes this regulation will not 
significantly impact

[[Page 69816]]

the overall energy supply, distribution, and use.

Unfunded Mandates

    This final rule does impose unfunded mandates under the Unfunded 
Mandates Reform Act of 1995, because it may result in the expenditure 
by the private sector of 100 million or more in any one year. The cost-
benefit analysis estimating yearly cost for operators to meet the final 
rule requirements has been placed in the docket. State pipeline safety 
programs will share inspection and enforcement responsibilities for the 
integrity management regulation. State regulators have participated in 
our meetings with the industry and research institutions on various 
integrity management issue discussions and have provided 
recommendations during our meetings and conference calls. State 
pipeline safety officials have expressed concern that the rule is to be 
sufficiently clear to enable them to enforce it and that there needs to 
be training for state inspectors. The final rule has been significantly 
modified to improve its clarity and enforceability and specific state 
comments on these areas have been addressed in sections discussing the 
changes. RSPA/OPS has planned an approach to enforcement that includes 
the extensive use of protocols for inspectors (both Federal and State) 
to use for compliance inspections and for training in the use of these 
protocols. RSPA/OPS has included funding for training inspectors within 
the budget for implementation of integrity management program. RSPA/OPS 
does not charge states tuition for pipeline safety training. In 
addition, 50 percent of a state's incidental costs of attending 
training is reimbursable through the grants program. Similar training 
is already underway regarding the integrity rule for hazardous liquid 
pipelines. Local public safety officials will be asked, but not 
required, to assist in identifying HCAs for the additional protections. 
In addition, industry associations are planning workshops in the 
development process to assist in identification of HCAs. We believe 
there are no disproportionate budgetary effects upon any particular 
region of the nation. We believe it is the least burdensome alternative 
that achieves the objective of the rule, because it gives options to 
industry on how to implement the rule.

National Environmental Policy Act

    We have evaluated the final rule for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.) and have concluded 
that this action would not significantly affect the quality of the 
environment. The Environmental Assessment determined that the combined 
impacts of the baseline assessment (pressure testing, internal 
inspection, or direct assessment), the periodic reassessments, and the 
additional preventive and mitigative measures that may be implemented 
for gas pipeline segments that could affect HCAs will result in 
positive environmental impacts. The number of incidents and the 
environmental damage from failures near HCAs is likely to be reduced. 
However, from a national perspective, the impact is not expected to be 
significant.
    Although the effects of the final rule will likely lead to fewer 
incidents, gas pipeline leaks that lead to adverse environmental 
impacts are rare under current conditions. Although the damage from 
failures could be reduced, the environmental damage resulting from gas 
pipeline failures is usually minor under current conditions. The 
effects are typically negligible, but can consist of localized, 
temporary damage to the environment in the immediate vicinity of the 
failure location on the pipeline.
    Some operators covered by the final rule already have integrity 
assessment programs. These operators typically consider the pipeline's 
proximity to populated areas when making decisions about where and when 
to inspect and test pipelines. As a result, some pipeline segments that 
could impact high consequence areas have already been recently 
assessed, and others would be assessed in the next several years 
without the provisions of the final rule. The primary effect of the 
final rule--accelerating integrity assessment in some high consequence 
areas--shifts increased integrity assurance forward for a few years for 
some segments that could affect 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 failure in these locations.
    The final rule does require operators to conduct an integrated 
assessment of the potential threats to pipeline integrity, and to 
consider additional preventive and mitigative risk control measures to 
provide enhanced protection. If there is a vulnerability to a 
particular failure cause, these assessments 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.
    Some gas pipeline operators already perform integrity evaluations 
or risk assessments that consider the environmental impacts. These 
evaluations have already led to additional risk controls beyond 
existing requirements to improve protection for these locations. For 
many segments, it is probable that operators will determine that the 
existing preventive and mitigative activities provide adequate 
protection to high consequence areas, and that the small additional 
risk reduction benefits of additional risk controls are not justified.
    The primary benefit of the final rule will be to establish 
requirements for conducting integrity assessments and periodic 
evaluations of integrity of segments that could impact high consequence 
areas. This will codify the integrity management programs and 
assessments operators are currently implementing. It will also require 
other operators, who have little, or no, integrity assessment and 
evaluation programs to raise their level of performance. Thus, the 
final rule is expected to ensure a more consistent, and overall higher 
level of protection for high consequence areas across the industry.
    The Environmental Assessment of this final rule is available for 
review in the docket.

List of Subjects in 49 CFR Part 192

    High consequence areas, Incorporation by reference, Integrity 
management, Pipeline safety, Potential impact areas, Reporting and 
recordkeeping requirements.

0
In consideration of the foregoing, RSPA/OPS is amending part 192 of 
title 49 of the Code of Federal Regulations as follows:

PART 192--[AMENDED]

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

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


Sec.  192.761  [Removed]

0
2. Section 192.761 is removed.

0
3. In part 192, under the heading of Pipeline Integrity Management, a 
new subpart O is added to read as follows:
Subpart O--Pipeline Integrity Management
Sec.
192.901 What do the regulations in this subpart cover?

[[Page 69817]]

192.903 What definitions apply to this subpart?
192.905 How does an operator identify a high consequence area?
192.907 What must an operator do to implement this subpart?
192.909 How can an operator change its integrity management program?
192.911 What are the elements of an integrity management program?
192.913 When may an operator deviate its program from certain 
requirements of this subpart?
192.915 What knowledge and training must personnel have to carry out 
an integrity management program?
192.917 How does an operator identify potential threats to pipeline 
integrity and use the threat identification in its integrity 
program?
192.919 What must be in the baseline assessment plan?
192.921 How is the baseline assessment to be conducted?
192.923 How is direct assessment used and for what threats?
192.925 What are the requirements for using External Corrosion 
Direct Assessment (ECDA)?
192.927 What are the requirements for using Internal Corrosion 
Direct Assessment (ICDA)?
192.929 What are the requirements for using Direct Assessment for 
Stress Corrosion Cracking (SCCDA)?
192.931 How may Confirmatory Direct Assessment (CDA) be used?
192.933 What actions must be taken to address integrity issues?
192.935 What additional preventive and mitigative measures must an 
operator take to protect the high consequence area?
192.937 What is a continual process of evaluation and assessment to 
maintain a pipeline's integrity?
192.939 What are the required reassessment intervals?
192.941 What is a low stress reassessment?
192.943 When can an operator deviate from these reassessment 
intervals?
192.945 What methods must an operator use to measure program 
effectiveness?
192.947 What records must an operator keep?
192.949 How does an operator notify OPS?
192.951 Where does an operator file a report?
Appendix A to Part 192--Incorporated by Reference
Appendix E to Part 192--Guidance on Determining High Consequence 
Areas and on carrying out requirements in the Integrity Management 
Rule

Subpart O--Pipeline Integrity Management


Sec.  192.901  What do the regulations in this subpart cover?

    This subpart prescribes minimum requirements for an integrity 
management program on any gas transmission pipeline covered under this 
part. For gas transmission pipelines constructed of plastic, only the 
requirements in Sec. Sec.  192.917, 192.921, 192.935 and 192.937 apply.


Sec.  192.903  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Assessment is the use of nondestructive testing techniques as 
allowed in this subpart to ascertain the condition of a covered 
pipeline segment.
    Confirmatory direct assessment is an assessment method using more 
focused application of the principles and techniques of direct 
assessment to identify internal and external corrosion in a covered 
transmission pipeline segment.
    Covered segment or covered pipeline segment means a segment of gas 
transmission pipeline located in a high consequence area. The terms gas 
and transmission line are defined in Sec.  192.3.
    Direct assessment is an integrity assessment method that utilizes a 
process to evaluate certain threats (i.e., external corrosion, internal 
corrosion and stress corrosion cracking) to a covered pipeline 
segment's integrity. The process includes the gathering and integration 
of risk factor data, indirect examination or analysis to identify areas 
of suspected corrosion, direct examination of the pipeline in these 
areas, and post assessment evaluation.
    High consequence area means an area established by one of the 
methods described in paragraphs (1) or (2) as follows:
    (1) An area defined as--
    (i) A Class 3 location under Sec.  192.5; or
    (ii) A Class 4 location under Sec.  192.5; or
    (iii) Any area outside a Class 3 or Class 4 location where the 
potential impact radius is greater than 660 feet (200 meters), and the 
area within a potential impact circle contains 20 or more buildings 
intended for human occupancy; or
    (iv) The area within a potential impact circle containing an 
identified site.
    (2) The area within a potential impact circle containing
    (i) 20 or more buildings intended for human occupancy, unless the 
exception in paragraph (d) applies; or
    (ii) An identified site.
    (3) Where a potential impact circle is calculated under either 
method (1) or (2) to establish a high consequence area, the length of 
the high consequence area extends axially along the length of the 
pipeline from the outermost edge of the first potential impact circle 
that contains either an identified site or 20 or more buildings 
intended for human occupancy to the outermost edge of the last 
contiguous potential impact circle that contains either an identified 
site or 20 or more buildings intended for human occupancy. (See Figure 
E.I.A. in appendix E.)
    (4) If in identifying a high consequence area under paragraph 
(1)(iii) of this definition or paragraph (2)(i) of this definition, the 
radius of the potential impact circle is greater than 660 feet (200 
meters), the operator may identify a high consequence area based on a 
prorated number of buildings intended for human occupancy within a 
distance 660 feet (200 meters) from the centerline of the pipeline 
until December17, 2006. If an operator chooses this approach, the 
operator must prorate the number of buildings intended for human 
occupancy based on the ratio of an area with a radius of 660 feet (200 
meters) to the area of the potential impact circle (i.e., the prorated 
number of buildings intended for human occupancy is equal to [20 x (660 
feet [or 200 meters ]/ potential impact radius in feet [or meters]) 
\2\]).
    Identified site means each of the following areas:
    (a) An outside area or open structure that is occupied by twenty 
(20) or more persons on at least 50 days in any twelve (12)-month 
period. (The days need not be consecutive.) Examples include but are 
not limited to, beaches, playgrounds, recreational facilities, camping 
grounds, outdoor theaters, stadiums, recreational areas near a body of 
water, or areas outside a rural building such as a religious facility); 
or
    (b) A building that is occupied by twenty (20) or more persons on 
at least five (5) days a week for ten (10) weeks in any twelve (12)-
month period. (The days and weeks need not be consecutive.) Examples 
include, but are not limited to, religious facilities, office 
buildings, community centers, general stores, 4-H facilities, or roller 
skating rinks); or
    (c) A facility occupied by persons who are confined, are of 
impaired mobility, or would be difficult to evacuate. Examples include 
but are not limited to hospitals, prisons, schools, day-care 
facilities, retirement facilities or assisted-living facilities.
    Potential impact circle is a circle of radius equal to the 
potential impact radius (PIR).
    Potential impact radius (PIR) means the radius of a circle within 
which the potential failure of a pipeline could have significant impact 
on people or property. PIR is determined by the formula r = 0.69* 
(square root of (p*d \2\)), where `r' is the radius of a circular area 
in feet surrounding the

[[Page 69818]]

point of failure, `p' is the maximum allowable operating pressure 
(MAOP) in the pipeline segment in pounds per square inch and `d' is the 
nominal diameter of the pipeline in inches.

    Note: 0.69 is the factor for natural gas. This number will vary 
for other gases depending upon their heat of combustion. An operator 
transporting gas other than natural gas must use section 3.2 of 
ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; ibr, see Sec.  
192.7) to calculate the impact radius formula.

    Remediation is a repair or mitigation activity an operator takes on 
a covered segment to limit or reduce the probability of an undesired 
event occurring or the expected consequences from the event.


Sec.  192.905  How does an operator identify a high consequence area?

    (a) General. To determine which segments of an operator's 
transmission pipeline system are covered by this subpart, an operator 
must identify the high consequence areas. An operator must use method 
(1) or (2) from the definition in Sec.  192.903 to identify a high 
consequence area. An operator may apply one method to its entire 
pipeline system, or an operator may apply one method to individual 
portions of the pipeline system. An operator must describe in its 
integrity management program which method it is applying to each 
portion of the operator's pipeline system. The description must include 
the potential impact radius when utilized to establish a high 
consequence area. (See appendix E.I. for guidance on identifying high 
consequence areas.)
    (b)(1) Identified sites. An operator must identify an identified 
site, for purposes of this subpart, from information the operator has 
obtained from routine operation and maintenance activities and from 
public officials with safety or emergency response or planning 
responsibilities who indicate to the operator that they know of 
locations that meet the identified site criteria. These public 
officials could include officials on a local emergency planning 
commission or relevant Native American tribal officials.
    (2) If a public official with safety or emergency response or 
planning responsibilities informs an operator that it does not have the 
information to identify an identified site, the operator must use one 
of the following sources, as appropriate, to identify these sites.
    (i) Visible marking (e.g., a sign); or
    (ii) The site is licensed or registered by a Federal, State, or 
local government agency; or
    (iii) The site is on a list (including a list on an internet web 
site) or map maintained by or available from a Federal, State, or local 
government agency and available to the general public.
    (c) Newly identified areas. When an operator has information that 
the area around a pipeline segment not previously identified as a high 
consequence area could satisfy any of the definitions in Sec.  192.903, 
the operator must complete the evaluation using method (1) or (2). If 
the segment is determined to meet the definition as a high consequence 
area, it must be incorporated into the operator's baseline assessment 
plan as a high consequence area within one year from the date the area 
is identified.


Sec.  192.907  What must an operator do to implement this subpart?

    (a) General. No later than December 17, 2004, an operator of a 
covered pipeline segment must develop and follow a written integrity 
management program that contains all the elements described in Sec.  
192.911 and that addresses the risks on each covered transmission 
pipeline segment. The initial integrity management program must 
consist, at a minimum, of a framework that describes the process for 
implementing each program element, how relevant decisions will be made 
and by whom, a time line for completing the work to implement the 
program element, and how information gained from experience will be 
continuously incorporated into the program. The framework will evolve 
into a more detailed and comprehensive program. An operator must make 
continual improvements to the program.
    (b) Implementation Standards. In carrying out this subpart, an 
operator must follow the requirements of this subpart and of ASME/ANSI 
B31.8S (ibr, see Sec.  192.7) and its appendices, where specified. An 
operator may follow an equivalent standard or practice only when the 
operator demonstrates the alternative standard or practice provides an 
equivalent level of safety to the public and property. In the event of 
a conflict between this subpart and ASME/ANSI B31.8S, the requirements 
in this subpart control.


Sec.  192.909  How can an operator change its integrity management 
program?

    (a) General. An operator must document any change to its program 
and the reasons for the change before implementing the change.
    (b) Notification. An operator must notify OPS, in accordance with 
Sec.  192.949, of any change to the program that may substantially 
affect the program's implementation or may significantly modify the 
program or schedule for carrying out the program elements. An operator 
must also notify a State or local pipeline safety authority when a 
covered segment is located in a State where OPS has an interstate agent 
agreement, and a State or local pipeline safety authority that 
regulates a covered pipeline segment within that State. An operator 
must provide the notification within 30 days after adopting this type 
of change into its program.


Sec.  192.911  What are the elements of an integrity management 
program?

    An operator's initial integrity management program begins with a 
framework (see Sec.  192.907) and evolves into a more detailed and 
comprehensive integrity management program, as information is gained 
and incorporated into the program. An operator must make continual 
improvements to its program. The initial program framework and 
subsequent program must, at minimum, contain the following elements. 
(When indicated, refer to ASME/ANSI B31.8S (ibr, see Sec.  192.7) for 
more detailed information on the listed element.)
    (a) An identification of all high consequence areas, in accordance 
with Sec.  192.905.
    (b) A baseline assessment plan meeting the requirements of Sec.  
192.919 and Sec.  192.921.
    (c) An identification of threats to each covered pipeline segment, 
which must include data integration and a risk assessment. An operator 
must use the threat identification and risk assessment to prioritize 
covered segments for assessment (Sec.  192.917) and to evaluate the 
merits of additional preventive and mitigative measures (Sec.  192.935) 
for each covered segment.
    (d) A direct assessment plan, if applicable, meeting the 
requirements of Sec.  192.923, and depending on the threat assessed, of 
Sec. Sec.  192.925, 192.927, or 192.929.
    (e) Provisions meeting the requirements of Sec.  192.933 for 
remediating conditions found during an integrity assessment.
    (f) A process for continual evaluation and assessment meeting the 
requirements of Sec.  192.937.
    (g) If applicable, a plan for confirmatory direct assessment 
meeting the requirements of Sec.  192.931.
    (h) Provisions meeting the requirements of Sec.  192.935 for adding 
preventive and mitigative measures to protect the high consequence 
area.
    (i) A performance plan as outlined in ASME/ANSI B31.8S, section 9 
that includes performance measures meeting the requirements of Sec.  
192.943.

[[Page 69819]]

    (j) Record keeping provisions meeting the requirements of Sec.  
192.947.
    (k) A management of change process as outlined in ASME/ANSI B31.8S, 
section 11.
    (l) A quality assurance process as outlined in ASME/ANSI B31.8S, 
section 12.
    (m) A communication plan that includes the elements of ASME/ANSI 
B31.8S, section 10, and that includes procedures for addressing safety 
concerns raised by--
    (1) OPS; and
    (2) A State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement.
    (n) Procedures for providing (when requested), by electronic or 
other means, a copy of the operator's risk analysis or integrity 
management program to--
    (1) OPS; and
    (2) A State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement.
    (o) Procedures for ensuring that each integrity assessment is being 
conducted in a manner that minimizes environmental and safety risks.
    (p) A process for identification and assessment of newly-identified 
high consequence areas. (See Sec.  192.905 and Sec.  192.921.)


Sec.  192.913  When may an operator deviate its program from certain 
requirements of this subpart?

    (a) General. ASME/ANSI B31.8S (ibr, see Sec.  192.7) provides the 
essential features of a performance-based or a prescriptive integrity 
management program. An operator that uses a performance-based approach 
that satisfies the requirements for exceptional performance in 
paragraph (b) of this section may deviate from certain requirements in 
this subpart, as provided in paragraph (c) of this section.
    (b) Exceptional performance. An operator must be able to 
demonstrate the exceptional performance of its integrity management 
program through the following actions.
    (1) To deviate from any of the requirements set forth in paragraph 
(c) of this section, an operator must have a performance-based 
integrity management program that meets or exceed the performance-based 
requirements of ASME/ANSI B31.8S and includes, at a minimum, the 
following elements--
    (i) A comprehensive process for risk analysis;
    (ii) All risk factor data used to support the program;
    (iii) A comprehensive data integration process;
    (iv) A procedure for applying lessons learned from assessment of 
covered pipeline segments to pipeline segments not covered by this 
subpart;
    (v) A procedure for evaluating every incident, including its cause, 
within the operator's sector of the pipeline industry for implications 
both to the operator's pipeline system and to the operator's integrity 
management program;
    (vi) A performance matrix that demonstrates the program has been 
effective in ensuring the integrity of the covered segments by 
controlling the identified threats to the covered segments;
    (vii) Semi-annual performance measures beyond those required in 
Sec.  192.943 that are part of the operator's performance plan. (See 
Sec.  192.911(i).) An operator must submit these measures, by 
electronic or other means, on a semi-annual frequency to OPS in 
accordance with Sec.  192.951; and
    (viii) An analysis that supports the desired integrity reassessment 
interval and the remediation methods to be used for all covered 
segments.
    (2) In addition to the requirements for the performance-based plan, 
an operator must--
    (i) Have completed at least two integrity assessments of all 
covered pipeline segments, and be able to demonstrate that each 
assessment effectively addressed the identified threats on the covered 
segments.
    (ii) Remediate all anomalies identified in the more recent 
assessment according to the requirements in Sec.  192.933, and 
incorporate the results and lessons learned from the more recent 
assessment into the operator's data integration and risk assessment.
    (c) Deviation. Once an operator has demonstrated that it has 
satisfied the requirements of paragraph (b) of this section, the 
operator may deviate from the prescriptive requirements of ASME/ANSI 
B31.8S and of this subpart only in the following instances.
    (1) The time frame for reassessment as provided in Sec.  192.939 
except that reassessment by some method allowed under this subpart 
(e.g., confirmatory direct assessment) must be carried out at intervals 
no longer than seven years;
    (2) The time frame for remediation as provided in Sec.  192.933 if 
the operator demonstrates the time frame will not jeopardize the safety 
of the covered segment.


Sec.  192.915  What knowledge and training must personnel have to carry 
out an integrity management program?

    (a) Supervisory personnel. The integrity management program must 
provide that each supervisor whose responsibilities relate to the 
integrity management program possesses and maintains a thorough 
knowledge of the integrity management program and of the elements for 
which the supervisor is responsible. The program must provide that any 
person who qualifies as a supervisor for the integrity management 
program has appropriate training or experience in the area for which 
the person is responsible.
    (b) Persons who carry out assessments and evaluate assessment 
results. The integrity management program must provide criteria for the 
qualification of any person--
    (1) Who conducts an integrity assessment allowed under this 
subpart; or
    (2) Who reviews and analyzes the results from an integrity 
assessment and evaluation; or
    (3) Who makes decisions on actions to be taken based on these 
assessments.
    (c) Persons responsible for preventive and mitigative measures. The 
integrity management program must provide criteria for the 
qualification of any person--
    (1) Who implements preventive and mitigative measures to carry out 
this subpart, including the marking and locating of buried structures; 
or
    (2) Who directly supervises excavation work carried out in 
conjunction with an integrity assessment.


Sec.  192.917  How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    (a) Threat identification. An operator must identify and evaluate 
all potential threats to each covered pipeline segment. Potential 
threats that an operator must consider include, but are not limited to, 
the threats listed in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 
2 and the following:
    (1) Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    (2) Static or resident threats, such as fabrication or construction 
defects;
    (3) Time independent threats such as third party damage and outside 
force damage; and
    (4) Human error.
    (b) Data gathering and integration. To identify and evaluate the 
potential threats to a covered pipeline segment, an operator must 
gather and integrate

[[Page 69820]]

data and information on the entire pipeline that could be relevant to 
the covered segment. In performing this data gathering and integration, 
an operator must follow the requirements in ASME/ANSI B31.8S, section 
4. At a minimum, an operator must gather and evaluate the set of data 
specified in appendix A to ASME/ANSI B31.8S, and consider both on the 
covered segment and similar non-covered segments, past incident 
history, corrosion control records, continuing surveillance records, 
patrolling records, maintenance history, internal inspection records 
and all other conditions specific to each pipeline.
    (c) Risk assessment. An operator must conduct a risk assessment 
that follows ASME/ANSI B31.8S, section 5, and considers the identified 
threats for each covered segment. An operator must use the risk 
assessment to prioritize the covered segments for the baseline and 
continual reassessments (Sec. Sec.  192.919, 192.921, 192.937), and to 
determine what additional preventive and mitigative measures are needed 
(Sec.  192.935) for the covered segment.
    (d) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must assess the threats to each covered segment 
using the information in sections 4 and 5 of ASME B31.8S, and consider 
any threats unique to the integrity of plastic pipe.
    (e) Actions to address particular threats. If an operator 
identifies any of the following threats, the operator must take the 
following actions to address the threat.
    (1) Third party damage. An operator must utilize the data 
integration required in paragraph (b) of this section and ASME/ANSI 
B31.8S, appendix A7 to determine the susceptibility of each covered 
segment to the threat of third party damage. If an operator identifies 
the threat of third party damage, the operator must implement 
comprehensive additional preventive measures in accordance with Sec.  
192.935 and monitor the effectiveness of the preventive measures. If, 
in conducting a baseline assessment under Sec.  192.921, or a 
reassessment under Sec.  192.937, an operator uses an internal 
inspection tool, such as a caliper, geometry or magnetic flux leakage 
tool, to address other identified threats on the covered segment, the 
operator must integrate data from these tool runs with data related to 
any encroachment or foreign line crossing on the covered segment, to 
define where potential indications of third party damage may exist in 
the covered segment. An operator must also have procedures in its 
integrity management program addressing actions it will take to respond 
to findings from this data integration.
    (2) Cyclic fatigue. An operator must evaluate whether cyclic 
fatigue or other loading condition (including ground movement, 
suspension bridge condition) could lead to a failure of a deformation, 
including a dent or gouge, or other defect in the covered segment. An 
evaluation must assume the presence of threats in the covered segment 
that could be exacerbated by cyclic fatigue. An operator must use the 
results from the evaluation together with the criteria used to evaluate 
the significance of this threat to the covered segment to prioritize 
the integrity baseline assessment or reassessment.
    (3) Manufacturing and construction defects. If an operator 
identifies the threat of manufacturing and construction defects 
(including seam defects) in the covered segment, an operator must 
analyze the covered segment to determine the risk of failure from these 
defects. An operator may consider manufacturing and construction 
related defects to be stable defects if the operating conditions on the 
covered segment have not significantly changed since December 17, 1998. 
If any of the following changes occur in the covered segment, an 
operator must prioritize the covered segment as a high risk segment for 
the baseline assessment or a subsequent reassessment.
    (i) Operating pressure increases above the historic operating 
pressure (i.e. the highest pressure recorded since December 17, 1998);
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) ERW pipe. If a covered pipeline segment contains low frequency 
electric resistance welded pipe (ERW) or lap welded pipe that satisfies 
the conditions specified in ASME/ANSI B31.8 S, appendix A4.3 and A4.4, 
an operator must select an assessment technology or technologies with a 
proven application capable of assessing seam integrity and of detecting 
seam corrosion anomalies. The operator must prioritize the covered 
segment as a high risk segment for the baseline assessment or a 
subsequent reassessment.
    (5) Corrosion. If an operator identifies corrosion on a covered 
pipeline segment that could adversely affect the integrity of the line 
(conditions specified in Sec.  192.931), the operator must evaluate and 
remediate, as necessary, all pipeline segments (both covered and non-
covered) with similar material coating and environmental 
characteristics. An operator must establish a schedule for evaluating 
and remediating, as necessary, the similar segments that is consistent 
with the operator's established operating and maintenance procedures 
under part 192 for testing and repair.


Sec.  192.919  What must be in the baseline assessment plan?

    An operator must include each of the following elements in its 
written baseline assessment plan:
    (a) Identification of the potential threats to each covered 
pipeline segment and the information supporting the threat 
identification. (See Sec.  192.917.);
    (b) The methods selected to assess the integrity of the line pipe, 
including an explanation of why the assessment method was selected to 
address the identified threats to each covered segment. The integrity 
assessment method an operator uses must be based on the threats 
identified to the covered segment. (See Sec.  192.917.) More than one 
method may be required to address all the threats to the covered 
pipeline segment;
    (c) A schedule for completing the integrity assessment of all 
covered segments, including risk factors considered in establishing the 
assessment schedule;
    (d) If applicable, a direct assessment plan that meets the 
requirements of Sec. Sec.  192.923, and depending on the threat to be 
addressed, of Sec.  192.925, Sec.  192.927, or Sec.  192.929; and
    (e) A procedure to ensure that the baseline assessment is being 
conducted in a manner that minimizes environmental and safety risks.


Sec.  192.921  How is the baseline assessment to be conducted?

    (a) Assessment methods. An operator must assess the integrity of 
the line pipe in each covered segment by applying one or more of the 
following methods depending on the threats to which the covered segment 
is susceptible. An operator must select the method or methods best 
suited to address the threats identified to the covered segment (See 
Sec.  192.917).
    (1) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the covered segment is 
susceptible. An operator must follow ASME/ANSI B31.8S (ibr, see Sec.  
192.7), section 6.2 in selecting the appropriate internal inspection 
tools for the covered segment.
    (2) Pressure test conducted in accordance with subpart J of this 
part;
    (3) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. An operator must 
conduct the direct

[[Page 69821]]

assessment in accordance with the requirements listed in Sec.  192.923 
and with, as applicable, the requirements specified in Sec. Sec.  
192.925, 192.927 or 192.929;
    (4) Other technology that an 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) 
180 days before conducting the assessment, in accordance with Sec.  
192.949.
    (b) Prioritizing segments. An operator must prioritize the covered 
pipeline segments for the baseline assessment according to a risk 
analysis that considers the potential threats to each covered segment. 
The risk analysis must comply with the requirements in Sec.  192.917.
    (c) Assessment for particular threats. In choosing an assessment 
method for the baseline assessment of each covered segment, an operator 
must take the actions required in Sec.  192.917(d) to address 
particular threats that it has identified.
    (d) Time period. An operator must prioritize all the covered 
segments for assessment in accordance with Sec.  192.917 (c) and 
paragraph (b) of this section. An operator must assess at least 50% of 
the covered segments beginning with the highest risk segments, by 
December 17, 2007. An operator must complete the baseline assessment of 
all covered segments by December 17, 2012.
    (e) Prior assessment. An operator may use a prior integrity 
assessment conducted before December 17, 2002 as a baseline assessment 
for the covered segment, if the integrity assessment meets the baseline 
requirements in this subpart and subsequent remedial actions to address 
the conditions listed in Sec.  192.933 have been carried out. In 
addition, if an operator uses this prior assessment as its baseline 
assessment, the operator must reassess the line pipe in the covered 
segment according to the requirements of Sec.  192.937 and Sec.  
192.939.
    (f) Newly identified areas. When an operator identifies a new high 
consequence area (see Sec.  192.205), an operator must complete the 
baseline assessment of the line pipe in the newly identified high 
consequence area within ten (10) years from the date the area is 
identified.
    (g) Newly installed pipe. An operator must complete the baseline 
assessment of a newly installed segment of pipe covered by this subpart 
within ten (10) years from the date the pipe is installed. An operator 
may conduct a post-installation pressure test, in accordance with 
subpart J of part 192, to satisfy the requirement for a baseline 
assessment.
    (h) Plastic transmission pipeline. If the threat analysis required 
in Sec.  192.917(d) on a plastic transmission pipeline indicates that a 
covered segment is susceptible to failure from causes other than third-
party damage, an operator must conduct a baseline assessment of the 
segment in accordance with the requirements of this section and of 
Sec.  192.917. The operator must justify the use of an alternative 
assessment method that will address the identified threats to the 
covered segment.


Sec.  192.923  How is direct assessment used and for what threats?

    (a) General. An operator may use direct assessment either as a 
primary assessment method or as a supplement to the other assessment 
methods allowed under this subpart. An operator may only use direct 
assessment as the primary assessment method to address the identified 
threats of external corrosion (ECDA), internal corrosion (ICDA), and 
stress corrosion cracking (SCCDA).
    (b) Primary method. An operator using direct assessment as a 
primary assessment method must have a plan that complies with the 
requirements in--
    (1) ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 6.4; NACE 
RP0502-2002 (ibr, see Sec.  192.7); and Sec.  192.925 if addressing 
external corrosion (ECDA).
    (2) ASME/ANSI B31.8S, section 6.4 and appendix B2, and Sec.  
192.927 if addressing internal corrosion (ICDA).
    (3) ASME/ANSI B31.8S, appendix A3, and Sec.  192.929 if addressing 
stress corrosion cracking (SCCDA).
    (c) Supplemental method. An operator using direct assessment as a 
supplemental assessment method for any applicable threat must have a 
plan that follows the requirements for confirmatory direct assessment 
in Sec.  192.931.


Sec.  192.925  What are the requirements for using External Corrosion 
Direct Assessment (ECDA)?

    (a) Definition. ECDA is a four-step process that combines 
preassessment, indirect inspection, direct examination, and post 
assessment to evaluate the threat of external corrosion to the 
integrity of a pipeline.
    (b) General requirements. An operator that uses direct assessment 
to assess the threat of external corrosion must follow the requirements 
in this section, in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 
6.4, and NACE RP 0502-2002 (ibr, see Sec.  192.7). An operator must 
develop and implement a direct assessment plan that has procedures 
addressing preassessment, indirect inspections, direct examination, and 
post-assessment.
    (1) Preassessment. In addition to the requirements in ASME/ANSI 
B31.8S section 6.4 and NACE RP 0502-2002, section 3, the plan's 
procedures for preassessment must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment; and
    (ii) The basis on which an operator selects at least two different, 
but complementary indirect assessment tools to assess each ECDA Region. 
If an operator utilizes an indirect inspection method that is not 
discussed in appendix A of NACE RP0502-2002, the operator must 
demonstrate the applicability, validation basis, equipment used, 
application procedure, and utilization of data for the inspection 
method.
    (2) Indirect Examination. In addition to the requirements in ASME/
ANSI B31.8S section 6.4 and NACE RP 0502-2002, section 4, the plan's 
procedures for indirect examination of the ECDA regions must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment;
    (ii) Criteria for identifying and documenting those indications 
that must be considered for excavation and direct examination. Minimum 
identification criteria include the known sensitivities of assessment 
tools, the procedures for using each tool, and the approach to be used 
for decreasing the physical spacing of indirect assessment tool 
readings when the presence of a defect is suspected;
    (iii) Criteria for defining the urgency of excavation and direct 
examination of each indication identified during the indirect 
examination. These criteria must specify how an operator will define 
the urgency of excavating the indication as immediate, scheduled or 
monitored; and
    (iv) Criteria for scheduling excavation of indications for each 
urgency level.
    (3) Direct examination. In addition to the requirements in ASME/
ANSI B31.8S section 6.4 and NACE RP 0502-2002, section 5, the plan's 
procedures for direct examination of indications from the indirect 
examination must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment;
    (ii) Criteria for deciding what action should be taken if either 
(a) corrosion

[[Page 69822]]

defects are discovered that exceed allowable limits (section 5.5.2.2 of 
NACE RP0502-2002), or
    (b) root cause analysis reveals conditions for which ECDA is not 
suitable (section 5.6.2 of NACE RP0502-2002);
    (iii) Criteria and notification procedures for any changes in the 
ECDA Plan, including changes that affect the severity classification, 
the priority of direct examination, and the time frame for direct 
examination of indications; and
    (iv) Criteria that describe how and on what basis an operator will 
reclassify and reprioritize any of the provisions that are specified in 
section 5.9 of NACE RP0502-2002.
    (4) Post assessment and continuing evaluation. In addition to the 
requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502-2002, 
section 6, the plan's procedures for post assessment of the 
effectiveness of the ECDA process must include--
    (i) Measures for evaluating the long-term effectiveness of ECDA in 
addressing external corrosion in covered segments; and
    (ii) Criteria for evaluating whether conditions discovered by 
direct examination of indications in each ECDA region indicate a need 
for reassessment of the covered segment at an interval less than that 
specified in Sec.  192.939. (See appendix D of NACE RP0502-2002.)


Sec.  192.927  What are the requirements for using Internal Corrosion 
Direct Assessment (ICDA)?

    (a) Definition. Internal Corrosion Direct Assessment (ICDA) is a 
process an operator uses to identify areas along the pipeline where 
fluid or other electrolyte introduced during normal operation or by an 
upset condition may reside, and then focuses direct examination on the 
locations in covered segments where internal corrosion is most likely 
to exist. The process identifies the potential for internal corrosion 
caused by microorganisms, or fluid with CO2, O2, hydrogen sulfide or 
other contaminants present in the gas.
    (b) General requirements. An operator using direct assessment as an 
assessment method to address internal corrosion in a covered pipeline 
segment must follow the requirements in this section and in ASME/ANSI 
B31.8S (ibr, see Sec.  192.7), section 6.4 and appendix B2. The ICDA 
process described in this section applies only for a segment of pipe 
transporting nominally dry natural gas, and not for a segment with 
electrolyte nominally present in the gas stream. If an operator uses 
ICDA to assess a covered segment operating with electrolyte present in 
the gas stream, the operator must develop a plan that demonstrates how 
it will conduct ICDA in the segment to effectively address internal 
corrosion.
    (c) The ICDA plan. An operator must develop and follow an ICDA plan 
that provides for preassessment, identification of ICDA regions and 
excavation locations, detailed examination of pipe at excavation 
locations, and post-assessment evaluation and monitoring.
    (1) Preassessment. In the preassessment stage, an operator must 
gather and integrate data and information needed to evaluate the 
feasibility of ICDA for the covered segment, and to support use of a 
model to identify the locations along the pipe segment where 
electrolyte may accumulate, to identify ICDA regions, and to identify 
areas within the covered segment where liquids may potentially be 
entrained. This data and information includes, but is not limited to--
    (i) All data elements listed in appendix A2 of ASME/ANSI B31.8S;
    (ii) Information needed to support use of a model that an operator 
must use to identify areas along the pipeline where internal corrosion 
is most likely to occur. (See paragraph (a) of this section.) This 
information, includes, but is not limited to, location of all gas input 
and withdrawal points on the line; location of all low points on 
covered segments such as sags, drips, inclines, valves, manifolds, 
dead-legs, and traps; the elevation profile of the pipeline in 
sufficient detail that angles of inclination can be calculated for all 
pipe segments; and the diameter of the pipeline, and the range of 
expected gas velocities in the pipeline;
    (iii) Operating experience data that would indicate historic upsets 
in gas conditions, locations where these upsets have occurred, and 
potential damage resulting from these upset conditions; and
    (iv) Information on covered segments where cleaning pigs may not 
have been used or where cleaning pigs may deposit electrolytes.
    (2) ICDA region identification. An operator's plan must identify 
where all ICDA Regions are located in the transmission system, in which 
covered segments are located. An ICDA Region extends from the location 
where liquid may first enter the pipeline and encompasses the entire 
area along the pipeline where internal corrosion may occur and where 
further evaluation is needed. An ICDA Region may encompass one or more 
covered segments. In the identification process, an operator must use 
the model in GRI 02-0057, ``Internal Corrosion Direct Assessment of Gas 
Transmission Pipelines--Methodology,'' (ibr, see Sec.  192.7). An 
operator may use another model if the operator demonstrates it is 
equivalent to the one shown in GRI 02-0057. A model must consider 
changes in pipe diameter, locations where gas enters a line (potential 
to introduce liquid) and locations down stream of gas draw-offs (where 
gas velocity is reduced) to define the critical pipe angle of 
inclination above which water film cannot be transported by the gas.
    (3) Identification of locations for excavation and direct 
examination. An operator's plan must identify the locations where 
internal corrosion is most likely in each ICDA region. In the location 
identification process, an operator must identify a minimum of two 
locations for excavation within each ICDA Region within a covered 
segment and must perform a direct examination for internal corrosion at 
each location, using ultrasonic thickness measurements, radiography, or 
other generally accepted measurement technique. One location must be 
the low point (e.g., sags, drips, valves, manifolds, dead-legs, traps) 
within the covered segment nearest to the beginning of the ICDA Region. 
The second location must be at the upstream end of the pipe containing 
a covered segment, having a slope not exceeding the critical angle of 
inclination nearest the end of the ICDA Region. If corrosion exists at 
either location, the operator must--
    (i) Evaluate the severity of the defect (remaining strength) and 
remediate the defect in accordance with Sec.  192.933;
    (ii) As part of the operator's current integrity assessment either 
perform additional excavations in each covered segment within the ICDA 
region, or use an alternative assessment method allowed by this subpart 
to assess the line pipe in each covered segment within the ICDA region 
for internal corrosion; and
    (iii) Evaluate the potential for internal corrosion in all pipeline 
segments (both covered and non-covered) in the operator's pipeline 
system with similar characteristics to the ICDA region containing the 
covered segment in which the corrosion was found, and as appropriate, 
remediate the conditions the operator finds in accordance with Sec.  
192.933.
    (4) Post-assessment evaluation and monitoring. An operator's plan 
must provide for evaluating the effectiveness of the ICDA process and 
continued monitoring of covered segments where internal corrosion has 
been identified.

[[Page 69823]]

The evaluation and monitoring process includes--
    (i) Evaluating the effectiveness of ICDA as an assessment method 
for addressing internal corrosion and determining whether a covered 
segment should be reassessed at more frequent intervals than those 
specified in Sec.  192.939. This evaluation must be carried out in the 
same year in which ICDA is used; and
    (ii) Continually monitoring each covered segment where internal 
corrosion has been identified using techniques such as coupons, UT 
sensors or electronic probes, periodically drawing off liquids at low 
points and chemically analyzing the liquids for the presence of 
corrosion products. An operator must base the frequency of the 
monitoring and liquid analysis on results from all integrity 
assessments that have been conducted in accordance with the 
requirements of this subpart, and risk factors specific to the covered 
segment. If an operator finds any evidence of corrosion products in the 
covered segment, the operator must take prompt action in accordance 
with one of the two following required actions and remediate the 
conditions the operator finds in accordance with Sec.  192.933.
    (A) Conduct excavations of covered segments at locations downstream 
from where the electrolyte might have entered the pipe; or
    (B) Assess the covered segment using another integrity assessment 
method allowed by this subpart.
    (5) Other requirements. The ICDA plan must also include--
    (i) Criteria an operator will apply in making key decisions (e.g., 
ICDA feasibility, definition of ICDA Regions, conditions requiring 
excavation) in implementing each stage of the ICDA process;
    (ii) Provisions for applying more restrictive criteria when 
conducting ICDA for the first time on a covered segment and that become 
less stringent as the operator gains experience; and
    (iii) Provisions that analysis be carried out on the entire 
pipeline in which covered segments are present, except that application 
of the remediation criteria of Sec.  192.933 may be limited to covered 
segments.


Sec.  192.929  What are the requirements for using Direct Assessment 
for Stress Corrosion Cracking (SCCDA)?

    (a) Definition. Stress Corrosion Direct Assessment (SCCDA) is a 
process to assess a covered pipe segment for the presence of SCC 
primarily by systematically gathering and analyzing excavation data for 
pipe having similar operational characteristics and residing in a 
similar physical environment.
    (b) General requirements. An operator using direct assessment as an 
integrity assessment method to address stress corrosion cracking in a 
covered pipeline segment must have a plan that provides, at minimum, 
for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data for all covered 
segments to identify whether the conditions for SCC are present and to 
prioritize the covered segments for assessment. This process must 
include gathering and evaluating data related to SCC at all sites an 
operator excavates during the conduct of its pipeline operations where 
the criteria in ASME/ANSI B31.8S (ibr, see Sec.  192.7), appendix A3.3 
indicate the potential for SCC. This data includes at minimum, the data 
specified in ASME/ANSI B31.8S, appendix A3.
    (2) Assessment method. The plan must provide that if conditions for 
SCC are identified in a covered segment, an operator must assess the 
covered segment using an integrity assessment method specified in ASME/
ANSI B31.8S, appendix A3, and remediate the threat in accordance with 
ASME/ANSI B31.8S, appendix A3, section A3.4.


Sec.  192.931  How may Confirmatory Direct Assessment (CDA) be used?

    An operator using the confirmatory direct assessment (CDA) method 
as allowed in Sec.  192.937 must have a plan that meets the 
requirements of this section and of Sec. Sec.  192.925 (ECDA) and Sec.  
192.927 (ICDA).
    (a) Threats. An operator may only use CDA on a covered segment to 
identify damage resulting from external corrosion or internal 
corrosion.
    (b) External corrosion plan. An operator's CDA plan for identifying 
external corrosion must comply with Sec.  192.925 with the following 
exceptions.
    (1) The procedures for indirect examination may allow use of only 
one indirect examination tool suitable for the application.
    (2) The procedures for direct examination and remediation must 
provide that--
    (i) All immediate action indications must be excavated for each 
ECDA region; and
    (ii) At least one high risk indication that meets the criteria of 
scheduled action must be excavated in each ECDA region.
    (c) Internal corrosion plan. An operator's CDA plan for identifying 
internal corrosion must comply with Sec.  192.927 except that the 
plan's procedures for identifying locations for excavation may require 
excavation of only one high risk location in each ICDA region.
    (d) Defects requiring near-term remediation. If an assessment 
carried out under paragraph (b) or (c) of this section reveals any 
defect requiring remediation prior to the next scheduled assessment, 
the operator must schedule the next assessment in accordance with NACE 
RP 0502-2002 (ibr, see Sec.  192.7), section 6.2 and 6.3. If the defect 
requires immediate remediation, then the operator must reduce pressure 
consistent with Sec.  192.933 until the operator has completed 
reassessment using one of the assessment techniques allowed in Sec.  
192.937.


Sec.  192.933  What actions must be taken to address integrity issues?

    (a) General requirements. An operator must take prompt action to 
address all anomalous conditions that the operator discovers through 
the integrity assessment. In addressing all conditions, an operator 
must evaluate all anomalous conditions and remediate those that could 
reduce a pipeline's integrity. An operator must be able to demonstrate 
that the remediation of the condition will ensure that the condition is 
unlikely to pose a threat to the integrity of the pipeline until the 
next reassessment of the covered segment. If an operator is unable to 
respond within the time limits for certain conditions specified in this 
section, the operator must temporarily reduce the operating pressure of 
the pipeline or take other action that ensures the safety of the 
covered segment. If pressure is reduced, an operator must determine the 
temporary reduction in operating pressure using ASME/ANSI B31G (ibr, 
see Sec.  192.7) or AGA Pipeline Research Committee Project PR-3-805 
(``RSTRENG''; ibr, see Sec.  192.7) or reduce the operating pressure to 
a level not exceeding 80% of the level at the time the condition was 
discovered. (See appendix A to this part 192 for information on 
availability of incorporation by reference information). A reduction in 
operating pressure cannot exceed 365 days without an operator providing 
a technical justification that the continued pressure restriction will 
not jeopardize the integrity of the pipeline.
    (b) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about the condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after 
conducting an integrity assessment, obtain sufficient

[[Page 69824]]

information about a condition to make that determination, unless the 
operator demonstrates that the 180-day period is impracticable.
    (c) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule that 
prioritizes the conditions for evaluation and remediation. Unless a 
special requirement for remediating certain conditions applies, as 
provided in paragraph (d) of this section, an operator must follow the 
schedule in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 7, Figure 
4. If an operator cannot meet the schedule for any condition, the 
operator must justify the reasons why it cannot meet the schedule and 
that the changed schedule will not jeopardize public safety. An 
operator must notify OPS in accordance with Sec.  192.949 if it cannot 
meet the schedule and cannot provide safety through a temporary 
reduction in operating pressure or other action. An operator must also 
notify a State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement, and a State or local pipeline safety authority that 
regulates a covered pipeline segment within that State.
    (d) Special requirements for scheduling remediation.--(1) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must follow ASME/ANSI B31.8S, section 7 in providing for immediate 
repair conditions. To maintain safety, an operator must temporarily 
reduce operating pressure in accordance with paragraph (a) of this 
section or shut down the pipeline until the operator completes the 
repair of these conditions. An operator must treat the following 
conditions as immediate repair conditions:
    (i) A calculation of the remaining strength of the pipe shows a 
predicted failure pressure less than or equal to 1.1 times the maximum 
allowable operating pressure at the location of the anomaly. Suitable 
remaining strength calculation methods include, ASME/ANSI B31G; 
RSTRENG; or an alternative equivalent method of remaining strength 
calculation. These documents are incorporated by reference and 
available at the addresses listed in appendix A to part 192.
    (ii) A dent that has any indication of metal loss, cracking or a 
stress riser.
    (iii) An anomaly that in the judgment of the person designated by 
the operator to evaluate the assessment results requires immediate 
action.
    (2) One-year conditions. Except for conditions listed in paragraph 
(d)(1) and (d)(3) of this section, an operator must remediate any of 
the following within one year of discovery of the condition:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper \2/3\ of the pipe) with a depth greater than 6% of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than Nominal Pipe Size (NPS) 12).
    (ii) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or at a longitudinal seam weld.
    (3) Monitored conditions. An operator does not have to schedule the 
following conditions for remediation, but must record and monitor the 
conditions during subsequent risk assessments and integrity assessments 
for any change that may require remediation:
    (i) A dent with a depth greater than 6% of the pipeline diameter 
(greater than 0.50 inches in depth for a pipeline diameter less than 
NPS 12) located between the 4 o'clock position and the 8 o'clock 
position (bottom \1/3\ of the pipe).
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6% of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter 
less than Nominal Pipe Size (NPS) 12), and engineering analyses of the 
dent demonstrate critical strain levels are not exceeded.
    (iii) A dent with a depth greater than 2% of the pipeline's 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or a longitudinal seam 
weld, and engineering analyses of the dent and girth or seam weld 
demonstrate critical strain levels are not exceeded. These analyses 
must consider weld properties.


Sec.  192.935  What additional preventive and mitigative measures must 
an operator take to protect the high consequence area?

    (a) General requirements. An operator must take additional measures 
beyond those already required by Part 192 to prevent a pipeline failure 
and to mitigate the consequences of a pipeline failure in a high 
consequence area. An operator must base the additional measures on the 
threats the operator has identified to each pipeline segment. (See 
Sec.  192.917) An operator must conduct, in accordance with one of the 
risk assessment approaches in ASME/ANSI B31.8S (ibr, see Sec.  192.7), 
section 5, a risk analysis of its pipeline to identify additional 
measures to protect the high consequence area and enhance public 
safety. Such additional measures include, but are not limited to, 
installing Automatic Shut-off Valves or Remote Control Valves, 
installing computerized monitoring and leak detection systems, 
replacing pipe segments with pipe of heavier wall thickness, providing 
additional training to personnel on response procedures, conducting 
drills with local emergency responders and implementing additional 
inspection and maintenance programs.
    (b) Third party damage and outside force damage--(1) Third party 
damage. An operator must enhance its damage prevention program, as 
required under Sec.  192.614 of this part, with respect to a covered 
segment to prevent and minimize the consequences of a release due to 
third party or outside force damage. Enhanced measures to an existing 
damage prevention program include, at a minimum--
    (i) Using qualified personnel (see Sec.  192.915) for work an 
operator is conducting that could adversely affect the integrity of a 
covered segment, such as marking, locating, and direct supervision of 
known excavation work.
    (ii) Collecting in a central database information that is location 
specific on excavation damage that occurs in on covered and noncovered 
segments in the transmission system and the root cause analysis to 
support identification of targeted additional preventative and 
mitigative measures in the high consequence areas. This information 
must include recognized damage that is not required to be reported as 
an incident under part 191.
    (iii) Participating in one-call systems in locations where covered 
segments are present.
    (iv) Monitoring of excavations conducted on covered pipeline 
segments by pipeline personnel. When there is physical evidence of 
encroachment involving excavation near a covered segment, an operator 
must either excavate the area near the encroachment or conduct an above 
ground survey using methods defined in NACE RP-0502-2002 (ibr, see 
Sec.  192.7). An operator must excavate, and remediate, in accordance 
with ANSI/ASME B31.8S and Sec.  192.933 any indication of coating 
holidays or discontinuity warranting direct examination.
    (2) Outside force damage. If an operator determines that outside 
force (e.g., earth movement, floods, unstable suspension bridge) is a 
threat to the integrity of a covered segment, the operator must take 
measures to minimize the consequences to the covered segment from 
outside force damage. These measures include, but are not limited to, 
increasing the

[[Page 69825]]

frequency of aerial, foot or other methods of patrols, adding external 
protection, reducing external stress, and relocating the line.
    (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). 
If an operator determines, based on a risk analysis, that an ASV or RCV 
would be an efficient means of adding protection to a high consequence 
area in the event of a gas release, an operator must install the ASV or 
RCV. In making that determination, an operator must, at least, consider 
the following factors--swiftness of leak detection and pipe shutdown 
capabilities, the type of gas being transported, operating pressure, 
the rate of potential release, pipeline profile, the potential for 
ignition, and location of nearest response personnel.
    (d) Pipelines operating below 30% SMYS. With respect to a 
transmission pipeline operating below 30% SMYS located in a class 3 or 
4 area but not in a high consequence area, an operator must--
    (1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) 
of this section to the pipeline; and
    (2) Either monitor excavations near the pipeline, or conduct 
patrols as required by Sec.  192.705 of the pipeline at bi-monthly 
intervals. If an operator finds any indication of unreported 
construction activity, the operator must conduct a follow up 
investigation to determine if mechanical damage has occurred.
    (e) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must apply the requirements in paragraphs 
(b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered 
segments of the pipeline.


Sec.  192.937  What is a continual process of evaluation and assessment 
to maintain a pipeline's integrity?

    (a) General. After completing the baseline integrity assessment of 
a covered segment, an operator must continue to assess the line pipe of 
that segment at the intervals specified in Sec.  192.939 and 
periodically evaluate the integrity of each covered pipeline segment as 
provided in paragraph (b) of this section. An operator must reassess a 
covered segment on which a prior assessment is credited as a baseline 
under Sec.  192.921(e) by no later than December 17, 2009. An operator 
must reassess a covered segment on which a baseline assessment is 
conducted during the baseline period specified in Sec.  192.921(d) by 
no later than seven years after the baseline assessment of that covered 
segment unless the evaluation under paragraph (b) of this section 
indicates earlier reassessment.
    (b) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure the integrity of each covered segment. 
The periodic evaluation must be based on a data integration and risk 
assessment of the entire pipeline as specified in Sec.  192.917. For 
plastic transmission pipelines, the periodic evaluation is based on the 
threat analysis specified in 192.917(d). For all other transmission 
pipelines, the evaluation must consider the past and present integrity 
assessment results, data integration and risk assessment information 
(Sec.  192.917), and decisions about remediation (Sec.  192.933) and 
additional preventive and mitigative actions (Sec.  192.935). An 
operator must use the results from this evaluation to identify the 
threats specific to each covered segment and the risk represented by 
these threats.
    (c) Assessment methods. In conducting the integrity reassessment, 
an operator must assess the integrity of the line pipe in the covered 
segment by any of the following methods as appropriate for the threats 
to which the covered segment is susceptible (see Sec.  192.917), or by 
confirmatory direct assessment under the conditions specified in Sec.  
192.931.
    (1) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the covered segment is 
susceptible. An operator must follow ASME/ANSI B31.8S (ibr, see Sec.  
192.7), section 6.2 in selecting the appropriate internal inspection 
tools for the covered segment.
    (2) Pressure test conducted in accordance with subpart J of this 
part;
    (3) Direct assessment to address threats of external corrosion, 
internal corrosion, or stress corrosion cracking. An operator must 
conduct the direct assessment in accordance with the requirements 
listed in Sec.  192.923 and with as applicable, the requirements 
specified in Sec. Sec.  192.925, 192.927 or 192.929;
    (4) Other technology that an 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) 
180 days before conducting the assessment, in accordance with Sec.  
192.949.
    (5) Confirmatory direct assessment when used on a covered segment 
that is scheduled for reassessment at a period longer than seven years. 
An operator using this reassessment method must comply with Sec.  
192.931.


Sec.  192.939  What are the required reassessment intervals?

    An operator must comply with the following requirements in 
establishing the reassessment interval for the operator's covered 
pipeline segments.
    (a) Pipelines operating at or above 30% SMYS. An operator must 
establish a reassessment interval for each covered segment operating at 
or above 30% SMYS in accordance with the requirements of this section. 
The minimum reassessment interval by an allowable reassessment method 
is seven years. If an operator establishes a reassessment interval that 
is greater than seven years, the operator must, within the seven-year 
period, conduct a confirmatory direct assessment on the covered 
segment, and then conduct the follow-up reassessment at the interval 
the operator has established. A reassessment carried out using 
confirmatory direct assessment must be done in accordance with Sec.  
192.931. (For ease of reference, the table that follows this section 
sets forth the required reassessment intervals.)
    (1) Pressure test or internal inspection or other equivalent 
technology. An operator that uses pressure testing or internal 
inspection as an assessment method must establish the reassessment 
interval for a covered pipeline segment by--
    (i) Basing the interval on the identified threats for the segment 
as listed in Sec.  192.917 of this section and in ASME/ANSI B31.8S 
(ibr, see Sec.  192.7), section 9, Tables 6 and 7, and on the analysis 
of the results from the last integrity assessment and from the data 
integration and risk assessment required by Sec.  192.911; or
    (ii) Using the intervals specified for different stress levels of 
pipeline (operating at or above 30% SMYS) listed in ASME/ANSI B31.8S, 
section 5, Table 3.
    (2) External Corrosion Direct Assessment. An operator that uses 
ECDA that meets the requirements of this subpart must determine the 
reassessment interval according to the requirements in paragraphs 6.2 
and 6.3 of NACE RP0502-2002 (ibr, see Sec.  192.7).
    (3) Internal Corrosion or SCC Direct Assessment. An operator that 
uses ICDA or SCCDA in accordance with the requirements of this subpart 
must determine the reassessment interval according to the following 
calculation. However, the reassessment interval cannot exceed those 
specified for direct assessment in ASME/ANSI B31.8S, section 5, Table 
3.
    (i) Determine the largest defect most likely to remain in the 
covered segment

[[Page 69826]]

and the corrosion rate appropriate for the pipe, soil and protection 
conditions;
    (ii) Use the largest remaining defect as the size of the largest 
defect discovered in the SCC or ICDA segment; and
    (iii) Estimate the reassessment interval as half the time required 
for the largest defect to grow to a critical size.
    (b) Pipelines Operating Below 30% SMYS. An operator must establish 
a reassessment interval for each covered segment operating below 30% 
SMYS in accordance with the requirements of this section. The minimum 
reassessment interval by an allowable reassessment method is seven 
years. An operator must establish reassessment by at least one of the 
following--
    (1) Reassessment by pressure test, internal inspection or other 
equivalent technology following the requirements in paragraph (a)(1) of 
this section except that the stress level referenced in paragraph 
(a)(1)(ii) of this section would be adjusted to reflect the lower 
operating stress level. If an established interval is more than seven 
years, the operator must conduct by the seventh year of the interval 
either a confirmatory direct assessment in accordance with Sec.  
192.931, or a low stress reassessment in accordance with Sec.  192.941.
    (2) Reassessment by ECDA following the requirements in paragraph 
(a)(2) of this section.
    (3) Reassessment by ICDA or SCCDA following the requirements in 
paragraph (a)(3) of this section.
    (4) Reassessment by confirmatory direct assessment at 7-year 
intervals in accordance with Sec.  192.931, with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    (5) Reassessment by the low stress assessment method at 7-year 
intervals in accordance with Sec.  192.941 with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    For ease of reference, the following table sets forth the required 
reassessment intervals. Also refer to appendix E.II for guidance on 
Assessment Methods and Assessment schedule for Transmission Pipelines 
Operating Below 30% SMYS. In case of conflict between the rule and the 
guidance in the appendix, the requirements of the rule control.
    An operator must comply with the following requirements in 
establishing a reassessment interval for a covered segment:

                                          Maximum Reassessment Interval
----------------------------------------------------------------------------------------------------------------
                                                                 Pipeline operating at
          Assessment method             Pipeline operating at    or above 30% SMYS, up      Pipeline operating
                                          or above 50% SMYS           to 50% SMYS             below 30% SMYS
----------------------------------------------------------------------------------------------------------------
Internal Inspection Tool, Pressure     10 years (*)...........  15 years (*)...........  20 years.(**)
 Test or Direct Assessment.
Confirmatory Direct Assessment.......  7 years................  7 years................  7 years.
Low Stress Reassessment..............  Not applicable.........  Not applicable.........  7 years + ongoing
                                                                                          actions specified in
                                                                                          Sec.   192.941.
----------------------------------------------------------------------------------------------------------------
(*) A Confirmatory direct assessment as described in Sec.   192.931 must be conducted by year 7 in a 10-year
  interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the
  interval.

Sec.  192.941  What is a low stress reassessment?

    (a) General. An operator of a transmission line that operates below 
30% SMYS may use the following method to reassess a covered segment in 
accordance with Sec.  192.939. This method of reassessment addresses 
the threats of external and internal corrosion. The operator must have 
conducted a baseline assessment of the covered segment in accordance 
with the requirements of Sec. Sec.  192.919 and 192.921.
    (b) External corrosion. An operator must take one of the following 
actions to address external corrosion on the low stress covered 
segment.
    (1) Cathodically protected pipe. To address the threat of external 
corrosion on cathodically protected pipe in a covered segment, an 
operator must perform an electrical survey (i.e. indirect examination 
tool/method) at least every 7 years on the covered segment. An operator 
must use the results of each survey as part of an overall evaluation of 
the cathodic protection and corrosion threat for the covered segment. 
This evaluation must consider, at minimum, the leak repair and 
inspection records, corrosion monitoring records, exposed pipe 
inspection records, and the pipeline environment.
    (2) Unprotected pipe or cathodically protected pipe where 
electrical surveys are impractical. If an electrical survey is 
impractical on the covered segment an operator must--
    (i) Conduct leakage surveys as required by Sec.  192.706 at 4-month 
intervals; and
    (ii) Every 1\1/2\ years, identify and remediate areas of active 
corrosion by evaluating leak repair and inspection records, corrosion 
monitoring records, exposed pipe inspection records, and the pipeline 
environment.
    (c) Internal corrosion. To address the threat of internal corrosion 
on a covered segment, an operator must--
    (1) Conduct a gas analysis for corrosive agents at least once each 
calendar year;
    (2) Conduct periodic testing of fluids removed from the segment. At 
least once each calendar year test the fluids removed from each storage 
field that may affect a covered segment; and
    (3) At least every seven (7) years, integrate data from the 
analysis and testing required by paragraphs (c)(1)-(c)(2) with 
applicable internal corrosion leak records, incident reports, safety-
related condition reports, repair records, patrol records, exposed pipe 
reports, and test records, and define and implement appropriate 
remediation actions.


Sec.  192.943  When can an operator deviate from these reassessment 
intervals?

    (a) Waiver from reassessment interval in limited situations. In the 
following limited instances, OPS may allow a waiver from a reassessment 
interval required by Sec.  192.939 if OPS finds a waiver would not be 
inconsistent with pipeline safety.
    (1) Lack of internal inspection tools. An operator who uses 
internal inspection as an assessment method may be able to justify a 
longer assessment period for a covered segment if internal inspection 
tools are not available to assess the line pipe. To justify this, the 
operator must demonstrate that it cannot obtain the internal inspection 
tools within the required assessment period and that the actions the 
operator is taking in the interim ensure the integrity of the covered 
segment.
    (2) Maintain product supply. An operator may be able to justify a 
longer reassessment period for a covered

[[Page 69827]]

segment if the operator demonstrates that it cannot maintain local 
product supply if it conducts the reassessment within the required 
interval.
    (b) How to apply. If one of the conditions specified in paragraph 
(a) (1) or (a) (2) of this section applies, an operator may seek a 
waiver of the required reassessment interval. An operator must apply 
for a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days 
before the end of the required reassessment interval, unless local 
product supply issues make the period impractical. If local product 
supply issues make the period impractical, an operator must apply for 
the waiver as soon as the need for the waiver becomes known.


Sec.  192.945  What methods must an operator use to measure program 
effectiveness?

    (a) General. An operator must include in its integrity management 
program methods to measure, on a semi-annual basis, whether the program 
is effective in assessing and evaluating the integrity of each covered 
pipeline segment and in protecting the high consequence areas. These 
measures must include the four overall performance measures specified 
in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 9.4, and the 
specific measures for each identified threat specified in ASME/ANSI 
B31.8S, appendix A. An operator must submit these measures, by 
electronic or other means, on a semi-annual frequency to OPS in 
accordance with Sec.  192.951.
    (b) External Corrosion Direct assessment. In addition to the 
general requirements for performance measures in paragraph (a) of this 
section, an operator using direct assessment to assess the external 
corrosion threat must define and monitor measures to determine the 
effectiveness of the ECDA process. These measures must meet the 
requirements of Sec.  192.925. An operator must submit these measures, 
by electronic or other means, on a semi-annual frequency to OPS in 
accordance with Sec.  192.951.


Sec.  192.947  What records must an operator keep?

    An operator must maintain, for the useful life of the pipeline, 
records that demonstrate compliance with the requirements of this 
subpart. At minium, an operator must maintain the following records for 
review during an inspection.
    (a) A written integrity management program in accordance with Sec.  
192.907;
    (b) Documents supporting the threat identification and risk 
assessment in accordance with Sec.  192.917;
    (c) A written baseline assessment plan in accordance with Sec.  
192.919;
    (d) Documents to support any decision, analysis and process 
developed and used to implement and evaluate each element of the 
baseline assessment plan and integrity management program. Documents 
include those developed and used in support of any identification, 
calculation, amendment, modification, justification, deviation and 
determination made, and any action taken to implement and evaluate any 
of the program elements;
    (e) Documents that demonstrate personnel have the required 
training, including a description of the training program, in 
accordance with Sec.  192.915;
    (f) Schedule required by Sec.  192.933 that prioritizes the 
conditions found during an assessment for evaluation and remediation, 
including technical justifications for the schedule.
    (g) Documents to carry out the requirements in Sec. Sec.  192.923 
through 192.929 for a direct assessment plan;
    (h) Documents to carry out the requirements in Sec.  192.931 for 
confirmatory direct assessment;
    (i) Verification that an operator has provided any documentation or 
notification required by this subpart to be provided to OPS, and when 
applicable, a State authority with which OPS has an interstate agent 
agreement, and a State or local pipeline safety authority that 
regulates a covered pipeline segment within that State.


Sec.  192.949  How does an operator notify OPS?

    An operator must provide any notification required by this subpart 
by--
    (1) Sending the notification to the Information Resources Manager, 
Office of Pipeline Safety, Research and Special Programs 
Administration, U.S. Department of Transportation, Room 7128, 400 
Seventh Street, SW., Washington, DC 20590;
    (2) Sending the notification to the Information Resources Manager 
by facsimile to (202) 366-7128; or
    (3) Entering the information directly on the Integrity Management 
Database (IMDB) Web site at http://primis.rspa.dot.gov/gasimp/.


Sec.  192.951  Where does an operator file a report?

    An operator must send any performance report required by this 
subpart to the Information Resources Manager--
    (1) By mail to the Office of Pipeline Safety, Research and Special 
Programs Administration, U.S. Department of Transportation, Room 7128, 
400 Seventh Street SW., Washington, DC 20590;
    (2) Via facsimile to (202) 366-7128; or
    (3) Through the online reporting system provided by OPS for 
electronic reporting available at the OPS Home Page at http://ops.dot.gov.

0
3. Appendix A to part 192 is amended by adding paragraph (9) to section 
II.D, and by adding new sections II.F and II.G to read as follows:

Appendix A to Part 192--Incorporated by Reference

* * * * *
    II. * * *
    D. * * *
    (9) ASME/ANSI B31.8S-2001 (Supplement to B31.8), ``Managing 
System Integrity of Gas Pipelines,'' July 19, 2002.
    E. * * *

F. NACE International

    (1) NACE RP-0502-2002 ``Pipeline External Corrosion Direct 
Assessment Methodology,'' 2002.

G. Gas Research Institute

    (1) GRI 02-0057, ``Internal Corrosion Direct Assessment of Gas 
Transmission Pipelines--Methodology,'' April 1, 2002.

0
4. A new Appendix E to Part 192 is added to part 192 to read as 
follows:

Appendix E to Part 192--Guidance on Determining High Consequence Areas 
and on Carrying Out Requirements in the Integrity Management Rule

I. Guidance on Determining a High Consequence Area

    To determine which segments of an operator's transmission 
pipeline system are covered for purposes of the integrity management 
program requirements, an operator must identify the high consequence 
areas. An operator must use method (1) or (2) from the definition in 
Sec.  192.903 to identify a high consequence area. An operator may 
apply one method to its entire pipeline system, or an operator may 
apply one method to individual portions of the pipeline system. 
(Refer to figure E.I.A for a diagram of a high consequence area)
    (a) If an operator selects method (1), then:
    (1) All pipeline in class 3 and class 4 locations is considered 
to be in a high consequence area.
    (2) The operator is to calculate potential impact circles, as 
defined in Sec.  192.903, centered on the centerline of the pipeline 
for:
    (i) Any areas of its pipeline system that are not in class 3 or 
class 4 locations which could include an identified site as defined 
in Sec.  192.903, and
    (ii) Any pipeline in class 3 and class 4 locations for which the 
potential impact radius would be greater than 660 feet (200 meters) 
and for which an identified site may exist in the area more than 660 
feet (200 meters) but less than the potential impact radius from the 
pipeline.
    (3) The operator is to evaluate the potential impact circles to 
determine if they contain

[[Page 69828]]

identified sites, as defined in Sec.  192.903, in accordance with 
paragraph (c) of the same section.
    (4) The operator is to complete identification of high 
consequence areas by December 17, 2004.
    (b) If an operator selects method (2) then:
    (1) The operator is to calculate potential impact circles, as 
defined in Sec.  192.903, centered on the centerline of the pipeline 
for all areas of its pipeline where the circles could contain 20 
buildings intended for human occupancy or an identified site.
    (2) The operator is to evaluate the potential impact circles to 
determine if they contain 20 buildings intended for human occupancy. 
Each separate dwelling unit in a multiple dwelling unit building is 
counted as a separate building intended for human occupancy.
    (i) If the radius of the potential impact circle is greater than 
660 feet (200 meters), the operator may identify a high consequence 
area based on a prorated number of buildings intended for human 
occupancy until December 17, 2006. If an operator chooses this 
approach, the operator must prorate the number of buildings intended 
for human occupancy based on the ratio of an area with a radius of 
660 feet (200 meters) to the area of the potential impact circle 
(i.e., the prorated number of buildings intended for human occupancy 
is equal to [20 x (660 feet [or 200 meters ]/ potential impact 
radius in feet [or meters])2]).
    (3) The operator is to evaluate the potential impact circles to 
determine if they contain identified sites, as defined in Sec.  
192.903, in accordance with paragraph (c) of this section.
    (4) The operator is to complete identification of high 
consequence areas by December 17, 2004.
    (c) Operators are to identify sites meeting the criteria of 
identified sites, as defined in Sec.  192.903. The process for 
identification is in Sec.  192.905. Further guidance was provided in 
(68 FR 42456; July 17, 2003) titled issuance of advisory bulletin. 
Operators must document, and retain for review during inspections, 
their rationale for selecting the source(s) used, including why it/
they are appropriate for use.
    (d) Requirements for incorporating newly identified high 
consequence areas into an integrity management program are in Sec.  
192.905.
BILLING CODE 4910-60-P

[[Page 69829]]

[GRAPHIC] [TIFF OMITTED] TR15DE03.000

II. Guidance on Assessment Methods for Transmission Pipelines 
Operating Below 30% SMYS

    (a) Table E.II.1 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats, for transmission pipelines operating below 30% 
SMYS not in HCAs (i.e. outside of potential impact circle) but 
located within Class 3 and 4 Locations.
    (b) Table E.II.2 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats, for transmission pipelines operating below 30% 
SMYS in HCAs.
    (c) Table E.II.3 gives guidance on preventative & mitigative 
measures addressing time dependent and independent

[[Page 69830]]

threats for transmission pipelines that operate below 30% SMYS, in 
HCAs.
[GRAPHIC] [TIFF OMITTED] TR15DE03.001


[[Page 69831]]


[GRAPHIC] [TIFF OMITTED] TR15DE03.002


[[Page 69832]]


[GRAPHIC] [TIFF OMITTED] TR15DE03.003


[[Page 69833]]


[GRAPHIC] [TIFF OMITTED] TR15DE03.004


[[Page 69834]]


[GRAPHIC] [TIFF OMITTED] TR15DE03.005


[[Page 69835]]


[GRAPHIC] [TIFF OMITTED] TR15DE03.006


[[Page 69836]]


[GRAPHIC] [TIFF OMITTED] TR15DE03.007



[[Page 69837]]


    Issued in Washington, DC, on December 2, 2003.
Samuel G. Bonasso,
Deputy Administrator.
[FR Doc. 03-30280 Filed 12-12-03; 8:45 am]
BILLING CODE 4910-60-C