{"operation":"document","citation":"67 FR 2136","title":"Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With Less Than 500 Miles of Pipelines)","source_type":"rulemaking","agency":"Research and Special Programs Administration","status":"historical","official":true,"published_on":"2002-01-16","effective_on":"2002-02-15","summary":"Our regulations for the transportation of hazardous liquids by pipeline require operators with 500 or more miles of regulated pipelines to establish a program for managing the integrity of pipelines that affect high consequence areas. The regulations require continual assessment and evaluation of pipeline integrity through inspection or testing, data integration and analysis, and follow-up remedial, preventive, and mitigative actions. This Final Rule extends those regulations to operators with less than 500 miles of regulated pipelines. We are taking this action because safety recommendations, statutory mandates, and accident analyses indicate that coordinated risk control measures are needed for public safety and environmental protection in addition to compliance with traditional safety standards. Broadening the coverage of the existing regulations will further enhance the protection of high consequence areas against the risk of pipeline failures.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-02-858.json","markdown":"https://regulus.evalyn.ai/document/federal-register-02-858.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-02-858","source_url":"https://www.federalregister.gov/documents/2002/01/16/02-858/pipeline-safety-pipeline-integrity-management-in-high-consequence-areas-hazardous-liquid-operators","body":"Federal Register, Volume 67 Issue 11 (Wednesday, January 16, 2002) [Federal Register Volume 67, Number 11 (Wednesday, January 16, 2002)] [Rules and Regulations] [Pages 2136-2144] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 02-858] [[Page 2136]] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Research and Special Programs Administration 49 CFR Part 195 [Docket No. RSPA-00-7408; Amdt. No. 195-76] RIN 2137-AD49 Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators With Less Than 500 Miles of Pipelines) AGENCY: Research and Special Programs Administration (RSPA), U.S. Department of Transportation (DOT). ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: Our regulations for the transportation of hazardous liquids by pipeline require operators with 500 or more miles of regulated pipelines to establish a program for managing the integrity of pipelines that affect high consequence areas. The regulations require continual assessment and evaluation of pipeline integrity through inspection or testing, data integration and analysis, and follow-up remedial, preventive, and mitigative actions. This Final Rule extends those regulations to operators with less than 500 miles of regulated pipelines. We are taking this action because safety recommendations, statutory mandates, and accident analyses indicate that coordinated risk control measures are needed for public safety and environmental protection in addition to compliance with traditional safety standards. Broadening the coverage of the existing regulations will further enhance the protection of high consequence areas against the risk of pipeline failures. DATES: This Final Rule takes effect February 15, 2002. FOR FURTHER INFORMATION CONTACT: L. M. Furrow by phone at 202-366-4559, by fax at 202-366-4566, by mail at U.S. Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590, or by e-mail at [email protected] . SUPPLEMENTARY INFORMATION: Background Last year we amended the regulations in 49 CFR part 195 to require each operator who owns or operates 500 or more miles of pipelines subject to part 195 to establish a program for managing the integrity of pipelines that could affect a high consequence area if a leak or rupture occurs (Docket No. RSPA-99-6355; 65 FR 75377; Dec. 1, 2000). High consequence areas include highly populated areas, areas unusually sensitive to environmental damage, and commercially navigable waterways (Sec. 195.450). Program standards require continual assessment, evaluation, correction, and validation of pipeline integrity (Sec. 195.452 and appendix C to part 195). The new standards took effect May 29, 2001 (66 FR 9532; Feb. 8, 2001). In addition, in a further rulemaking action (Docket No. RSPA-99-6355), we are revising the repair provisions of Sec. 195.452(h) and clarifying that Sec. 195.452 applies to carbon dioxide pipelines as well as hazardous liquid pipelines. We did not apply the new program standards to pipelines of operators with less than 500 miles of regulated pipelines primarily because we needed more information about the potential impact of the standards on these operators. We subsequently learned that these operators include, to a large extent, companies with ample resources and capabilities to carry out the standards. A wide range of persons who submitted comments to Docket No. RSPA- 99-6355 supported the need to apply the new program standards to all operators of regulated pipelines that could affect high consequence areas. Based on these comments and the impact information we had collected, we published a Notice of Proposed Rulemaking (NPRM) to extend the program standards to pipelines of operators with less than 500 miles of regulated pipelines (66 FR 15821; March 21, 2001). The NPRM did not propose any substantive change to the existing program standards. It merely proposed to establish later deadlines for developing programs under Sec. 195.452(b)(1), identifying pipelines under Sec. 195.452(b)(1)(i), completing baseline assessments under Sec. 195.452(d)(1), accepting prior assessments under Sec. 195.452(b)(2), and applying certain time limits on reviewing assessment results under Sec. 195.452(h)(3). We invited interested persons to submit written comments on the proposed rules until May 21, 2001. Although the NPRM proposed no substantive change to the program standards, in the earlier proceeding (Docket No. RSPA-99-6355), we invited comments until March 31, 2001, on the substance of the standard for remedial action (Sec. 195.452(h)). As indicated in the NPRM, if Sec. 195.452(h) is changed in that proceeding, the changes will apply to all operators of pipelines to which the program standards apply, including operators covered by the present Final Rule. Disposition of Comments This section of the preamble summarizes written comments we received in response to the NPRM. It also describes how we treated those comments in developing the final rules. However, comments related to costs and benefits and the impact of the proposed rules on small entities are addressed in the ``Regulatory Analyses and Notices'' section of this preamble. If a proposed rule is not mentioned, no significant comments were received on the proposal, and we are adopting the proposed rule as final. Eight persons submitted comments: a professional organization, the American Society of Safety Engineers (ASSE); a state pipeline safety agency, the Washington Utilities and Transportation Commission (WUTC); a Washington State advisory committee, the Citizens Advisory Committee on Pipeline Safety (CAC); the Small Business Administration (SBA); the Department of Energy (DOE); an engineering firm, Wink, Incorporated (Wink); and two pipeline operators, the Laclede Pipeline Company (Laclede) and the Tosco Corporation (Tosco). ASSE did not comment on specific proposals in the NPRM, but strongly supported our goal of assuring the integrity of pipeline systems. ASSE also said improving pipeline safety would improve the United States' competitive position in the world economy. WUTC, CAC, Tosco, and DOE expressed general support for the NPRM but, along with Wink, suggested changes. DOE also commented on the costs of the proposed rules in their impact on small entities. Laclede opposed the integrity assessment proposal and took issue with our estimate of compliance costs. SBA's comments were limited to the impact of the proposed rules on small entities. Under proposed Secs. 195.452(b)(1) and (b)(1)(i), operators with less than 500 miles of pipelines would have 9 months after the effective date of the final rules to identify all pipeline segments that could affect high consequence areas. They would have 1 year after the effective date to develop a written integrity management program that addresses the risks of those segments. Tosco said the identification of pipeline segments should occur after, not before, integrity management programs are completed, and suggested we allow operators 1 year to complete the identifications. In considering this comment, we noted that operators with 500 or more miles of pipelines have not indicated they expect any significant difficulties in meeting the 9-month identification rule. Tosco's comment [[Page 2137]] does not give us reason to believe the 9-month rule might be too burdensome for operators with less than 500 miles of pipelines. While Tosco is correct that operators will need to have relevant program elements in place to guide them in identifying pipeline segments, we believe 9 months is enough time to complete those elements and to carry out the identifications. The additional 3 months the existing rule provides for program development gives operators enough time to complete program elements other than those concerning identification. We do not think this additional time is also needed to identify pipeline segments. CAC suggested we require operators to seek input from potentially affected communities in identifying high consequence areas. CAC believed the input would help operators identify areas of population at risk and areas of economic importance. Although we recognize community input is valuable in many situations involving pipelines, particularly in site selection and emergency response, we do not feel it is necessary to mandate that operators seek the input CAC envisioned for two reasons. First, the definition of ``high consequence area'' in Sec. 195.450 covers CAC's concern about the population-at-risk. That definition refers to areas of high or concentrated population that the U.S. Census Bureau has defined and delineated. Operators should be able to identify these areas quite easily using Census Bureau data. If additional information is needed from community records to complete the identifications, the proposed rule would implicitly obligate operators to seek this information, making an explicit requirement unnecessary. Secondly, the NPRM did not propose to require integrity management of pipelines that could affect areas of economic significance other than commercially navigable waterways. These waterways, which operators also can readily identify without community input, arguably are the nation's foremost economic resources potentially at risk from pipeline spills. Other significant economic resources that may be affected by pipelines are less certain, and we feel the present regulations in Part 195 provide those resources adequate protection against the risk of pipeline spills. Similarly, in directing DOT to require additional inspection of certain pipelines, Congress did not include pipelines that affect economic resources other than commercially navigable waterways (49 U.S.C. 60102(f)(2) and 60109). If in the future there is a need to apply the integrity management rules to pipelines affecting other significant economic resources, we will consider whether operators should seek community input in identifying those resources. Although we did not adopt CAC's recommendations, it is important to note that in a separate proceeding we are considering the need for regulations on better communication of pipeline information by operators to local officials and the public. We have formed a communications work team, consisting of representatives from environmental and public safety organizations, pipeline companies, and government to aid our own hazardous liquid pipeline safety advisory committee in examining communications issues. Notices of meetings of the work group are published in the Federal Register, and minutes of the meetings are posted on this Web site: http://ops.dot.gov . WUTC suggested we require baseline integrity assessments of new pipelines as soon after they are constructed as possible, and for existing pipelines as soon as practicable after the final rules take effect. WUTC stated that early baseline assessment would provide the best basis for comparing subsequent assessment results. The NPRM proposed, in Sec. 195.452(d), that operators with less than 500 miles of pipeline complete baseline assessments within 7 years after the effective date of the final rule, with half the line pipe, selected by risk, assessed within 42 months after the effective date. Alternatively, operators could use as a baseline assessment any qualified integrity assessment completed within the 5 years prior to the effective date. For newly constructed pipelines, hydrostatic testing completed as required by other regulations in Part 195 will fulfill the baseline assessment requirement. Since this testing is normally part of the construction process, it should meet WUTC's objective of early assessment. For existing pipelines, we proposed 7 years to complete baseline assessments because of the volume of assessments, the limited availability of in-line inspection tools, and the time needed to schedule pressure testing to minimize service disruptions. Although we agree with WUTC that earlier baseline assessment would be beneficial, we do not think requiring earlier baseline assessments would be reasonable under present circumstances. To assure that only qualified persons develop integrity management programs and make program decisions, Wink suggested we require operators to use registered professional engineers with demonstrated technical pipeline expertise and experience. Wink further suggested we require operators to submit their integrity management programs for review by RSPA certified entities. We did not adopt either suggestion because to do so would go beyond the scope of the NPRM. While Sec. 195.452(f)(8) requires operators to use persons qualified to evaluate assessment results and analyze information, the NPRM did not address specific qualifications or program review by certified entities. Based on our experience in other areas of pipeline regulation, we believe operators will use qualified engineers with pipeline experience to assist in developing integrity management programs and recommend critical decisions under the programs. Moreover, persons carrying out regulated assessment and mitigation activities on pipelines are subject to the existing qualification requirements in Subpart G of Part 195. To assure that operators carry out their programs in accordance with the rules, we will use our own engineers and technical specialists to evaluate operators' programs and require changes that may be needed for safety. This type of evaluative process has been satisfactory for other programs and plans required by Part 195. We prefer to continue this approach to assure the quality of integrity management programs rather than establish additional personnel qualifications or a new federal certification program. Wink asked to what extent operators would have to consider potential terrorist activities in their ongoing assessments of pipeline integrity. Under one of the integrity management program requirements (Sec. 195.452(e)(1)), operators must schedule integrity assessments based on ``all risk factors that reflect the risk conditions on the pipeline.'' Therefore, if an operator knows or it is reasonable to anticipate that there is a threat to the integrity of the pipeline from terrorist activity, the operator must consider that risk in developing its integrity program. Since the events of September 11, 2001, we are working with DOT, the Department of Energy, the Federal Energy Regulatory Commission, and State agencies, to consider the need for minimum security standards for critical facilities. Wink postulated that construction permit timing could interfere with an operator's ability to meet remediation deadlines. Section 195.452(h) deals with this potential problem. Under this rule, if justifiable circumstances preclude an operator from meeting specified repair deadlines, the operator may reasonably extend the repair schedule if it [[Page 2138]] temporarily reduces operating pressure to a safe level or notifies us of the delay in making a permanent repair. Finally, Wink suggested we establish a program review process in which operators would meet with our technical specialists to examine whether the program meets applicable requirements. In response to Wink's first comment, we mentioned we will use our own engineers and technical specialists to evaluate operators' programs and require changes that may be needed for safety. We expect this review process will involve meeting with operators' representatives. Laclede, who operates a 28-mile propane pipeline serving a gas distribution system, believed it would be unreasonable to apply the proposed integrity assessment requirement (Sec. 195.452(c)) to its pipeline. Laclede said the design of 70 percent of its pipeline cannot accommodate internal inspection tools, and difficulties in de-watering the line after hydrostatic testing would cause control valve and instrument freeze-ups during critical cold weather periods. Laclede suggested we exempt from internal inspection or hydrostatic testing requirements all pipelines directly serving gas distribution systems if the pipeline is cathodically protected and inspected according to our standards or is equipped with emergency flow restricting or shutdown devices. We did not adopt this comment because providing adequate cathodic protection and meeting current inspection requirements cannot assure a pipeline is free from all potentially harmful defects that internal inspection or hydrostatic testing can disclose, such as mechanical damage or fatigue cracks. Also, while emergency flow restricting or shutdown devices are useful in mitigating the consequences of a pipeline rupture, these devices do nothing to prevent ruptures, which is the purpose of periodic internal inspection or hydrostatic testing. Laclede's comment did not fully explain the particular difficulties in de-watering, or drying, its pipeline after hydrostatic testing. Drying pipelines is not an uncommon problem in the industry and not one we believe makes the proposed testing rule unreasonable. Many companies are available to provide expert drying services, using techniques that depend on operating conditions. However, if an operator's circumstances are so unusual that hydrostatic testing would result in unavoidable damage to pipeline facilities and internal inspection is not a viable alternative, the operator may apply for a waiver of the testing requirement as permitted by 49 U.S.C. 60118. DOE was concerned that construction of new pipelines within the next few years to meet the growing demand for fossil fuels could tax available technical expertise and equipment needed to meet various assessment deadlines in the existing and proposed rules. DOE said available resources could be stretched to a point where meeting the deadlines would not be possible, or at least not possible without significantly increased costs. Therefore, DOE suggested we expand the present provisions for extending deadlines (e.g., Sec. 195.452(j)(4)) to include situations in which meeting a deadline would result in supply disruptions. We agree that by shifting resources away from new construction or shutting down vital pipelines for hydrostatic testing or repair, supply disruptions could occur. However, at this stage we believe the impact of such an eventuality is too speculative to warrant changing the rules to add supply disruption as an acceptable reason for extending deadlines. Also, over the next few years new technologies might become available that would enable acceptable integrity assessments with no effect on supply. If in the future a supply problem appears more likely, the operator involved may petition us for necessary relief or latitude under the rules. DOE also commented on our plan to identify high consequence areas on it's National Pipeline Mapping System (NPMS) and to make the information available to the public via the Internet. DOE recommended that before implementing this plan, we fully evaluate issues of critical infrastructure protection. Indeed, we designed the NPMS with infrastructure protection issues in mind. For example, to avoid creating a tool for intentional misuse of information with tragic results, critical pipeline components and operating data would not be shown on the NPMS. However, the events of September 11, 2001, have caused even greater concern about the security of critical infrastructure systems. As a result, the NPMS no longer provides open access to pipeline-related data. These data are only available to pipeline operators and local, state, and federal government officials. More information on the availability of data and how operators and officials can access it is on the NPMS home page: http://www.npms.rspa.dot.gov . Editing Changes In a further rulemaking action (Docket No. RSPA-99-6355), we are revising Sec. 195.452(h)(3) to eliminate the possibility that periods specified for reviewing integrity assessment results could cause confusion. This change to Sec. 195.452(h)(3) eliminates the need to revise that section to cover operators with less than 500 miles of regulated pipelines. Therefore, this Final Rule does not include the NPRM's proposed change to Sec. 195.452(h)(3). Because this Final Rule extends the coverage of existing Sec. 195.452 to all operators subject to part 195, there is no need to state in final Sec. 195.452 which operators are subject to Sec. 195.452. Therefore, we edited Sec. 195.452(a) to describe which pipelines are covered by Sec. 195.452 by moving relevant provisions in Sec. 195.452(b)(1) to Sec. 195.452(a). Section 195.452(a) now provides that Sec. 195.452 applies to hazardous liquid and carbon dioxide pipelines that could affect a high consequence area, including pipelines located in a high consequence area unless a risk assessment effectively shows the pipeline could not affect the area. The NPRM proposed certain compliance dates for covered pipelines that depend on whether the operator of the pipeline owns or operates 500 or more miles of regulated pipelines. Although no one commented on this approach to determining compliance dates, we now recognize the approach could have unintended results. Under the proposed approach, if the miles of regulated pipelines an operator owns or operates changes during the compliance period (through transfer, construction, or abandonment of pipelines), the compliance dates applicable to that operator's covered pipelines could also change. For example, if an operator currently subject to Sec. 195.452 were to reduce its miles of regulated pipelines below 500 during a compliance period for covered pipelines, the operator's covered pipelines would then fall under the later compliance date applicable to operators with less than 500 miles of regulated pipelines. Likewise, covered pipelines of operators who increase their miles of regulated pipelines to 500 or more during a compliance period would become subject to earlier compliance dates. The purpose of the proposed approach to determining compliance dates was merely to establish compliance dates for pipelines covered by the NPRM that are later than the existing compliance dates in Sec. 195.452. We did not intend that the existing or proposed compliance dates change with changes in an operator's regulated pipeline mileage. Rather, we intended to apply the existing and proposed compliance dates to covered pipelines existing on May 29, 2001 (the [[Page 2139]] effective date of existing Sec. 195.452), depending on whether, on that date, the operator owned or operated 500 or more miles of regulated pipelines. To clarify the application of compliance dates and to eliminate repetitive wording, final Sec. 195.452(a) divides covered pipelines into three categories. The first category includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to part 195. This category of pipelines is subject to the existing compliance dates in Sec. 195.452, and will remain subject to those dates regardless of how many miles of regulated pipelines the present or future operator of the pipelines owns or operates after May 29, 2001. The second category includes pipelines existing on May 29, 2001, that were owned or operated on that date by an operator who owned or operated less than 500 miles of pipeline subject to part 195. This category of pipelines is subject to the later compliance dates proposed in the NPRM for operators with less than 500 miles of regulated pipelines. Like the first category, the compliance dates applicable to the second category of pipelines do not depend on how many miles of regulated pipelines the present or future operator of the pipelines owns or operates after May 29, 2001. The third category of covered pipelines includes pipelines constructed or converted after May 29, 2001. Because these pipelines are not subject to the existing or proposed compliance dates, we have added appropriate dates to Secs. 195.452(b)(1), (b)(2)(i), (d)(1), and (h)(3). The dates in paragraphs (b)(1) and (h)(3) provide compliance periods equivalent to periods allowed for Category 1 or 2 pipelines. In paragraph (b)(2)(i), we set the date as the date the pipeline begins operation, because operators should not need any longer time to identify a new or converted pipeline as a covered pipeline. The date the pipeline begins operation is also the compliance date in paragraph (d)(1), because the hydrostatic test part 195 requires on new and converted pipelines before operation will serve as the baseline assessment. Advisory Committee Consideration We presented the NPRM for consideration by the Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) at a meeting in Washington, DC on August 13, 2001 (66 FR 35505; July 5, 2001). The THLPSSC is RSPA's statutory advisory committee for hazardous liquid pipeline safety. The committee has 15 members, representing industry, government, and the public. Each member is qualified to consider the technical feasibility, reasonableness, cost-effectiveness, and practicability of proposed pipeline safety standards. The committee voted unanimously to approve the rules proposed in the NPRM and the associated evaluation of costs and benefits. A transcript of the August 13 meeting is available in Docket No. RSPA-98-4470. Regulatory Analyses and Notices Executive Order 12866 and DOT Regulatory Policies and Procedures We consider this Final Rule to be a non-significant regulatory action under section 3(f) of Executive Order 12866 (58 FR 51735; October 4,1993). Therefore, the Office of Management and Budget (OMB) has not received a copy of this rulemaking to review. We do not consider this rulemaking to be significant under DOT regulatory policies and procedures (44 FR 11034; Feb. 26, 1979). This section of the preamble summarizes the findings of the Regulatory Evaluation we prepared for this Final Rule. A copy of the Regulatory Evaluation is in the docket. Pipeline spills can adversely affect human health and the environment. However, the magnitude of this impact differs from area to area. There are some areas in which the impact of a spill will be more significant than it would be in others due to concentrations of people who could be affected or to the presence of environmental resources that are unusually sensitive to damage. Because of the potential for dire consequences of pipeline failures in certain areas, these areas merit a higher level of protection. We are promulgating this Final Rule to afford the necessary additional protection to these high consequence areas. Last year we established 49 CFR 195.450 and 195.452, which are new requirements for additional protection of populated areas, commercially navigable waterways, and areas unusually sensitive to environmental damage from pipeline spills (65 FR 75377; Dec.1, 2000). The new requirements apply to pipeline operators who own or operate 500 or more miles of pipeline. This Final Rule extends the same requirements, with modified compliance deadlines, to the remaining operators of regulated pipelines--those that own or operate less than 500 miles of regulated pipeline. RSPA and the National Transportation Safety Board (NTSB) have conducted many investigations that have highlighted the importance of protecting the public and environmentally sensitive areas from pipeline failures. NTSB has made several recommendations to ensure the integrity of pipelines near populated and environmentally sensitive areas. These recommendations include requiring periodic testing and inspection to identify corrosion and other damage, establishing criteria to determine appropriate intervals for inspections and tests, determining hazards to public safety from electric resistance welded pipe, and requiring installation of automatic or remotely-operated mainline valves on high- pressure lines to provide for rapid shutdown of failed pipelines. Congress also directed DOT to undertake additional pipeline safety measures in areas of potentially high consequence. These statutory requirements call for new regulations on identifying pipelines in high density population areas, unusually sensitive environmental areas, and commercially navigable waters. They also call for new regulations on periodic inspections of pipelines in these areas with internal inspection devices, and on emergency flow restricting devices. This Final Rule requires operators to systematically manage pipeline integrity to reduce the potential for failures that could affect high consequence areas (populated areas, unusually sensitive areas, and commercially navigable waterways). Operators must develop and follow an integrity management program to identify pipeline segments that could affect high consequence areas, and continually assess, through internal inspection, pressure testing, or equivalent alternative technology, the integrity of those segments. The program must also evaluate the segments through comprehensive information analysis, remediate integrity problems, and provide additional protection through preventive and mitigative measures, including the use of emergency flow restricting devices. Existing Secs. 195.450 and 195.452 cover an estimated 86.7 percent of the 157,000 miles of regulated hazardous liquid pipeline in the U.S. This Final Rule covers the remaining 13.3 percent. Of this percentage, we estimate this Final Rule will impact approximately 5,440 miles of pipeline. We estimate the cost to operators to develop the necessary programs at approximately $9.94 million, with an additional annual cost for program upkeep and reporting of $1.32 million. An operator's program begins with a baseline assessment plan and a framework that addresses each [[Page 2140]] 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 high consequence areas, the program will be updated and improved, as needed. This Final Rule requires a baseline assessment of covered pipeline segments through internal inspection, pressure test, or use of other technology capable of equivalent performance. The baseline assessment must be completed within 7 years after this Final Rule goes into effect. After this baseline assessment, the rule further requires that operators periodically reassess and evaluate pipeline segments to ensure their integrity within a 5-year interval. We estimate the cost of periodic reassessment will generally not occur until the sixth year, unless the baseline assessment indicates significant defects that would require earlier reassessment. Integrating information related to the pipeline's integrity is a key element of the integrity management program. Costs will be incurred in realigning existing data systems to permit integration and in analysis of the integrated data by knowledgeable pipeline safety professionals. The total costs for the information integration requirements in this Final Rule are $6.6 million in the first year and $3.3 million annually thereafter. This Final Rule requires operators to identify and take preventive or mitigative actions that would enhance public safety or environmental protection, based on a risk analysis of the pipeline segment. One preventive or mitigative action involves installing an emergency flow restricting device on the pipeline segment, if determined necessary. We could not estimate the total cost of installing emergency flow restricting devices because we do not know how many operators will install them. Another action involves evaluating leak detection capability and modifying that capability, if necessary. We do not know how many operators currently have leak detection systems or how many systems will be installed or upgraded as a result of this Final Rule. Therefore, we are unable to estimate the total costs of the leak detection requirements. As a result of this Final Rule, we expect operators will assess more line pipe than they otherwise would assess. Integrity assessment consists of a baseline assessment, to be conducted within 7 years after the effective date of the final rule, and subsequent reassessment at intervals not to exceed every 5 years. We estimate the cost of additional baseline assessments at approximately $377,000 a year, and the cost of additional reassessments at approximately $531,000 a year. Cost impact will be greater in the sixth and seventh years after the effective date of the final rule due to an overlap between baseline inspection and the initial subsequent inspection. The additional costs in these two years are estimated at $5.26 million. We cannot easily quantify the benefits of this Final Rule, but we can describe them qualitatively. Issuance of this Final Rule ensures that all operators will perform at least to a baseline safety level and will contribute to an overall higher level of safety and environmental performance nationwide. The Final Rule will lead to greater uniformity in how risk is evaluated and addressed. It will also provide more clarity in discussions by government, industry and the public about safety and environmental issues, and how the issues can be resolved. Section 195.452 is written using a performance-based approach. This approach has several advantages. First, it encourages development and use of new technologies. Secondly, it supports operators' development of more formal, structured risk-based programs. Thirdly, it supports continual evaluation of the programs by RSPA and state inspectors. And lastly, it provides greater opportunity for operators to customize their long-term maintenance programs. Section 195.452 has stimulated the pipeline industry to develop its own consensus standard using a risk-based approach to integrity management. The rule has further fostered development of industry-wide technical standards, such as repair criteria to use following an internal inspection. The Final Rule encourages a balanced program, addressing the range of prevention and mitigation needs and avoiding reliance on any single tool or overemphasis on any single cause of failure. A balanced program will lead to addressing the most significant risks in populated areas, unusually sensitive environmental areas, and commercially navigable waterways, thus improving industry performance in these areas. The Final Rule requires a verification process that gives RSPA and state inspectors an opportunity to influence the methods of assessment and the interpretation of results. Government monitoring of the adequacy and implementation of this process should expedite the operators' rates of remedial action and reduce the public's exposure to risk. A particularly significant benefit of this Final Rule involves the information that operators will gather to support decisions. Two essential elements of the integrity management program are the continual assessment and evaluation of pipeline integrity using inspection and testing technology, and the integration and analysis of all available information about the pipeline. The processes of planning, assessment, and evaluation will provide operators with better data to use in determining a pipeline's condition and the location of potential problems that must be addressed. Also, government inspectors will be able to focus on potential risks and consequences that require greater scrutiny and the need for more intensive preventive and mitigation measures. The public has expressed concern about the danger pipelines may pose to their neighborhoods. The integrity management process leads to greater accountability to the public for both operators and DOT. This accountability is enhanced through our choice of a map-based approach to defining the areas most in need of additional protection--a visual depiction of pipelines in relation to populated areas, unusually sensitive environmental areas, and commercially navigable waterways. The system integrity requirements will assure the public that operators are continually inspecting and evaluating the threats to pipelines that pass through or close to populated areas. We have not estimated quantitative benefits for the continual integrity management evaluation required by this Final Rule. We do not believe, however, that requiring this comprehensive process, including the reassessment of pipelines every 5 years, will be an undue burden on operators. We believe the added security this assessment will provide and the generally expedited rate of strengthening the pipeline system in high consequence areas are benefit enough to promulgate these requirements. Laclede commented that we grossly underestimated implementation costs. Laclede notes that our estimate of the cost for all affected operators is $9.64 million, whereas Laclede expects itself to incur costs in excess of $1 million to modify its pipeline. Laclede's estimated costs are to replace piping that can not now be inspected with internal inspection devices. The rule does not require such pipe replacement, and costs for such replacement therefore were not included in the implementation cost estimate. The rule allows use of hydrostatic testing as an alternative to internal inspection. Laclede's replacement of piping to allow passage of internal inspection devices, if [[Page 2141]] undertaken, would be an operational choice based on the company's conclusion that internal inspection would be a better method of assessment than hydrostatic testing. Operators are free to make such operational choices, but they are not required by the rule, and costs associated with pipe replacement are not, therefore, a cost of implementing the rule. We fully considered the costs of hydrostatic testing in the Regulatory Evaluation. DOE expressed concern that costs associated with shutdown time during assessment or with obtaining permits to conduct repair activities may not have been included in the Regulatory Evaluation. DOE also thought per-mile cost estimates may not be appropriate for operators with only a few miles of pipe. With respect to the impact on small entities, DOE thought the requirements could have an unreasonable impact in some cases. The values we used to estimate costs for internal inspection and hydrostatic testing were based on detailed studies of both methods that considered all relevant costs. The outcome of those studies are per- mile estimates for conducting assessments. We recognize that costs may be higher for operators that have only a few miles of pipeline, and for whom ``fixed'' costs of assessment would be amortized over just a few miles. However, we are unable to estimate how many operators may be so affected. Many of the operators subject to this Final Rule are parts of larger companies, as described further in response to Small Business Administration comments, and should not be so affected. We will work with operators who may be unusually impacted, each of whom may request a waiver from particular requirements. While costs for permitting associated with conducting assessments were included, permitting costs associated with repairs were not estimated. No repair costs were included in the Regulatory Evaluation. This rule does impose time limits on the repair of certain types of defects. Generally, however, repair of conditions that could adversely affect the safe operation of a pipeline is already required by 49 CFR 195.401 and so is not a new requirement in this rule. Regulatory Flexibility Act Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), we must consider whether a rulemaking would have a significant impact on a substantial number of small entities. This Final Rule covers only those operators that own or operate less t","truncated":true,"body_characters":61284}