{"operation":"document","citation":"68 FR 69778","title":"Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)","source_type":"rulemaking","agency":"Research and Special Programs Administration","status":"historical","official":true,"published_on":"2003-12-15","effective_on":"2004-01-14","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.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-03-30280.json","markdown":"https://regulus.evalyn.ai/document/federal-register-03-30280.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-03-30280","source_url":"https://www.federalregister.gov/documents/2003/12/15/03-30280/pipeline-safety-pipeline-integrity-management-in-high-consequence-areas-gas-transmission-pipelines","body":"Federal Register, Volume 68 Issue 240 (Monday, December 15, 2003) [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 (Formerl","truncated":true,"body_characters":367864}