Performance-based standards allow an operator to select the most effective processes and technologies as they become available. OPS wants to create incentives for operators to invest in the development of new technology. Because internal inspection technology and other integrity monitoring equipment have changed considerably in recent years and are expected to continue to improve, we want to encourage operators to use and strive to improve the best available technologies and processes. Thus, rather than only specify the use of currently available technologies, parts of the rule are performance-based to allow operators to develop customized programs that address pipeline-specific characteristics, are fully integrated into company safety and environmental protection programs, and use the best available technologies to assess and repair pipelines.

The specification parts of the rule ensure uniformity among integrity management programs so that they all address key issues, such as baseline and continual integrity assessment intervals, information integration and analysis requirements, and time frames to review and analyze integrity assessment results and to complete remedial actions.

As suggested by commenters, we have revised the rule to allow an operator to modify its baseline assessment plan and to clarify the basis for an operator changing and improving its integrity management program. We have added a provision allowing an operator to modify its baseline assessment plan so long as the operator documents the modification and reasons for the modification. An operator would have to document any modification at the time the decision is made to modify the plan, not at the time the modification is implemented. OPS enforcement personnel would review these supporting documents during a field inspection.

Although reworded, the rule still provides that an integrity management program is a continually changing program. However, the rule now specifies that an operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. The rule also clarifies that an operator's integrity management program will evolve from the initial program framework the operator develops.

We have revised the rule to clarify that the integrity management program requirements apply to each pipeline segment that could affect a high consequence areas. An operator's program must address the risk factors each pipeline segment poses to a high consequence area.

The proposed rule specified required elements of an operator's integrity management program. Other than some minor word changes and edits, we have not changed those elements in the final rule. We believe these elements will ensure sound integrity management programs.

However, to address commenters' concerns that the proposed rule failed to specify a process for determining if a release could affect a high consequence area, we have added two related requirements: that, as a first step, an operator identify all pipeline segments that could affect a high consequence area and also include a process in its program for identifying which pipeline segments could affect a high consequence area. (Identifying those segments that could affect an area involves determining if a release from a segment in or near a high consequence area could affect the area.) Although we did not propose these requirements in the notice, we believe they were implicit. Whether explicitly stated or not, an operator would have to identify which pipeline segments could affect a high consequence area before determining how the line pipe in those segments would be assessed. Moreover, since the trigger for the integrity management program requirements is whether a pipeline segment could affect a high consequence area, an essential element must be a process for identifying those pipeline segments that could affect the defined high consequence areas. In the Appendix to the rule, we have also provided guidance to help an operator in identifying high consequence areas and in evaluating how a pipeline release could affect a high consequence area. This guidance will help an operator in developing the required process.

The final rule requires that an operator follow recognized industry practices unless the rule otherwise requires a different practice or the operator can demonstrate that an alternative practice is supported by a reliable engineering evaluation. Paragraph (b)(3) does not affect an operator's obligation to comply with all other requirements in this rule. In the final rule, we have changed the term best industry practices to recognized industry practices. We believe this is an easily understood term by operators and enforcement personnel. Recognized industry practices include those found in national consensus standards or reference guides, and generally conform to the practices of the American National Standards Institute. Companies' successful use of these practices helps determine their validity and acceptance. We have further revised the provision to clarify the basis for an operator using an alternative practice. The rule now provides that an operator's selection of an alternative must be based on a reliable engineering evaluation. Use of an alternative must provide an equivalent level of public safety and environmental protection. An operator must document its use of an alternative practice from when the operator makes the decision to use the alternative. An operator must be able to provide the documentation to OPS enforcement personnel for review during a field inspection.

We have not limited an operator's use of alternative practices to only when new technology is being used. For example, an alternative practice could be one that has been successfully used in other countries or by other pipeline companies but has not yet been codified into a national consensus standard. OPS wants to encourage operators to use innovative practices that are based on sound engineering judgment. OPS also wants to encourage innovation in technology and recognizes that an existing technology may be improved and given a new application.

We have also revised language throughout the rule to make the rule clearer and more understandable. These changes have not affected the requirements of the rule, most have simply been made to improve the rule's overall clarity and to ensure the consistency in use of terms. Others have been made to address DOJ's concerns about making the rule more specific and enforceable and clarifying the operator's required responsibilities under the rule. Any substantive changes are discussed in this document.

2. Remedial Actions - Proposed Section 195.452(g)

The proposed rule required an operator to take prompt action to address all pipeline integrity issues raised by the integrity assessment and data integration analysis. The rule proposed that an operator evaluate and repair all defects that could reduce a pipeline's integrity, and establish an evaluation and repair schedule. The rule did not propose time frames for making the repairs, other than an operator could not operate the affected part of its pipeline system until it had corrected a condition presenting an immediate hazard. The NPRM also asked for comment on whether the rule should contain specific time lines for conducting repairs.

API was against specific time lines and said that criteria for when repairs should be implemented could not be reduced to simple statements suitable for inclusion in the rule. API added that the consensus standard will offer guidance to operators. Enbridge stated that a one-size-fits-all time frame for conducting repairs is not practical or technically justified; however, Enbridge said that it supported the goal of ensuring that no imminent hazard is left unaddressed.

Environmental Defense recommended a relatively short time to conduct repairs after serious defects are identified, e.g., one month to complete repairs unless pipeline pressure is significantly reduced. The City of Austin said that the rule should include repair time lines, acceptable methods of remediation and a better definition of what pipeline flaws constitute an immediate hazard. The City of Bellingham also

recommended that the rule establish a specific and expeditious deadline for conducting repairs. EPA Region III commented that the proposed rule did not define what conditions constituted immediate hazard conditions.

Peoples Energy commented that the proposed language about which anomalies an operator had to evaluate and repair only applied to defects that could reduce integrity. Peoples Energy pointed out that this determination could not be made until an operator reviewed all data.

DOJ/ENRD questioned the ability to enforce performance-based standards, particularly with respect to the proposed repair provisions. DOJ/ENRD requested that the regulation be written in language that requires an operator to take specific action. DOJ/ENRD based its concerns on its experience with enforcing the Clean Water Act. DOJ/ENRD was particularly concerned that the proposed rule would not ensure that repairs were made before failures occurred and strongly recommended that language be added specifying when an operator would have to make repairs on the pipeline. DOJ/ENRD also strongly urged that the rule include a provision establishing a cut-off time for when an operator had to review and analyze the results from an internal inspection, and recommended a phased-in approach.

Response:

We have rewritten the remedial action section of the final rule to accommodate DOJ/ENRD's and other commenters' concerns. To be consistent with the wording used to describe required program elements, we have renamed the section to reflect the broader actions an operator must take to address integrity issues raised by the assessments. The rule has been revised to specify time frames for reviewing and analyzing the results of an integrity assessment and for completing repairs of certain conditions (see §195.452(h)).

The rule still requires an operator to take prompt action to address all pipeline integrity issues raised by the integrity assessment and information integration. The rule now clarifies that an operator is required to evaluate all anomalies and repair those that could affect the pipeline's integrity. Prompt action means that an operator must make the repair as soon as practical. However, an operator must prioritize the repairs according to the severity of each anomaly and address first those anomalies that pose the greatest risk to the pipeline's integrity.

The rule now requires that an operator complete repairs according to a schedule that prioritizes anomalies found during the integrity assessment for evaluation and repair. In this schedule, an operator would have to provide for review and analysis of the integrity assessment results by a date certain. The review and analysis must be done by a qualified person (i.e., a person who has the requisite knowledge and technical expertise to review the results and analyze the data.) For the first three years after the rule's effective date, an operator would determine the period by which the results would have to be reviewed and analyzed and commit that date in writing in its schedule. After the third year, an operator's schedule must provide for review and analysis of the integrity assessment results within 120 days of conducting each assessment. The rule allows more flexibility in the first three years so that OPS can review the adequacy of time frames operators establish, and gather sufficient information to determine what the required standard for review and analysis of assessment results should be. OPS recognizes that a time frame depends, in part, on the availability of persons with expertise to evaluate the data. OPS further recognizes that a quality review and analysis takes time. By the end of the third year OPS will have sufficient information to be able to determine if it should revise the 120-day required period.

An operator's schedule also has to provide time frames for evaluating and completing repairs. A qualified person must conduct the evaluation (i.e., a person with the requisite knowledge and technical expertise.) Because an operator must prioritize the repairs, the rule provides that the operator is to base the repair schedule on specified risk factors and pipeline-specific risk factors the operator develops. For conditions not specified in the rule, the operator determines the schedule for evaluation and repair. However, the rule provides the time frames in which an operator must complete repair of certain conditions on the pipeline. These conditions are listed as immediate repair conditions, 60-day conditions and 6-month conditions. The time frame required for repair starts at the time the operator discovers the condition on the pipeline, which occurs when an operator has adequate information about the condition to determine the need for repair. Depending on circumstances, an operator could have adequate information when the operator receives the preliminary internal inspection report, gathers and integrates information from other inspections or the periodic evaluation, excavates the anomaly, or receives the final internal inspection report.

In the proposed rule we used the term immediate hazard for certain conditions, and referenced §195.401(b). In the final rule we refer to these as immediate repair conditions and identify several. Under §195.401(b), an immediate hazard condition requires that an operator shut down the pipeline until the operator has corrected the condition. With an immediate repair condition, as long as safety is maintained, an operator will either be able to temporarily reduce operating pressure or shut down the pipeline until the operator can complete the repair of the condition.

An operator may deviate from the rule's specified repair times if the operator justifies the reasons why the schedule cannot be met and that the changed schedule will not jeopardize public safety or environmental protection. OPS enforcement personnel will review any justifications and supporting documents during site inspections. In certain cases when an operator cannot meet the required schedule and cannot provide safety through a temporary reduction in operating pressure, the operator must notify OPS. This will allow OPS to determine the extent of review needed and if an inspection is needed. The rule specifies how an operator must notify OPS.

In the NPRM we discussed the consensus standard that an ANSI workgroup was developing on integrity management. OPS has been participating in the work group. In the notice, we said that we would consider adopting all, or part of, the standard once it was final, but only after public notice and comment. (More discussion about the consensus standard appears later in this document under the topic heading "Consensus standard on pipeline integrity.") The standard is not yet final. However, OPS is basing the provisions in section 195.452(h) on initial indications of what will be in the final consensus standard. We believe that the criteria being considered by the standard's workgroup adequately address pipeline integrity concerns because the criteria are based on a structured methodology for evaluation of internal inspection devices data. The methodology is a recognized industry practice. The criteria are also based on well-established consensus standards, such as the American Society of Mechanical Engineers (ASME) B31.4 standard. ASME B31.4 is a widely-recognized and long accepted standard on liquid transportation systems for hydrocarbons, liquid petroleum gas, anhydrous ammonia, and alcohols. (The regulations in 49 CFR Part 195 were developed from ASME B31.4.)

Although a consensus integrity standard is not yet final, we have made available at OPS's website, notes of the meetings, and a peer review draft of the standard on Managing Pipeline System Integrity. The standard is expected to be completed and published in December, 2000.

We recognize that we have completely restructured the section of the rule pertaining to actions an operator must take to address pipeline integrity issues. Because of the extensive changes to this section of the rule, we are allowing 60 days comment on the provisions in section 195.452(h). Based on the comments we receive, we will consider modifying the provisions. At the end of the comment period, we will either issue a modification or a notice stating that the section stands as written.

An operator has one year from the effective date of the rule to develop the framework for an integrity management program. (The effective date is 60 days from when the final rule defining unusually sensitive environmental areas is published.) An operator has 3½ years from the rule's effective date to conduct a baseline integrity assessment of the highest risk line pipe segments. An operator is not likely to take remedial actions required by this rule until after the integrity assessment. Thus, remedial action criteria are not needed until some time after the rule's effective date. We expect to issue any modifications so that operators have ample time to incorporate the modifications into their program framework. If we are delayed in issuing the modification so that operators do not have adequate lead time, we will then consider further delaying the compliance date for section 195.452(h). Until OPS announces a modification, operators can base their program remedial action criteria on those set forth in this rule.

3. Review, Approval and Enforcement Processes

Some commenters questioned why the proposed rule did not provide for adequate and timely OPS review and approval of an operator's baseline plan, integrity assessments, and integrity program. The proposed rule requires an operator to maintain for inspection written documentation of its program and assessment plan, and of any evaluation or analysis made to support a decision or action. The rule did not propose requirements for formal transmittal of baseline assessment plans, assessment results, or integrity management programs to OPS for approval.

Lower Colorado River Authority (LCRA) supported the flexibility of a performance-based approach but cautioned that the commensurate accountability component seemed to be missing. LCRA explained that the proposed rule did not provide a mechanism for OPS review, or approval of critical decisions made by an operator or indicate that OPS would have any involvement in program implementation. The City of Austin maintained that the proposed rule seemed to continue reliance on the regulated community to implement pipeline safety regulations at their own discretion, with only minimal regulatory oversight. The City of Austin cautioned that close regulatory review and oversight are needed and strongly urged OPS to require all integrity management programs to be submitted for OPS approval, as well as assessment reports.

EPA Oil Program Center expressed concern that the proposed rule relied "heavily on a pipeline operator's assessments, assumptions, and evaluations, yet requires no formal approval process by the Office of Pipeline Safety or certification by a third party, such as a Professional Engineer."

Several commenters questioned OPS's ability to adequately enforce the proposed rule because of inadequate data, knowledge, or expertise. EPA Region III stated that the bulk of expertise in this subject area seemed to reside with the pipeline industry because of the proposed rule's reliance on industry's efforts to evaluate and resolve risk issues concerning pipelines. Region III further stated that OPS must obtain and/or develop independent expertise and knowledge for effective oversight. Friends of the Aquifer commented that because of the lack of accurate data about pipeline spills, OPS would not be able to judge the adequacy of the risk factors included in an operator's plan.

Response:

OPS agrees that an effective and credible inspection process is critical to achieving the objectives of the rule. OPS is developing protocols and criteria for detailed inspection of operator baseline assessment plans and integrity management programs to ensure that operators comply with the requirements of the rule, and that operators use structured, documented, and technically defensible processes and models to support assessment priorities and time frames, decisions on remediation, prevention and mitigation, and measures of program effectiveness.

OPS has already developed expertise in enforcing performance-based regulations and in evaluating risk-based decision processes. OPS has contracted for additional training in specific technical areas to improve the qualifications of its enforcement personnel. OPS plans to have a sufficient base of trained enforcement personnel who will review the integrity management programs during on-site inspections of pipeline operators. OPS will contract for any needed technical expertise to supplement the knowledge of its enforcement personnel.

We are not requiring formal approval of an operator's integrity management program or of decisions and analyses made to develop and implement the program. Rather, a multi-disciplined team composed of OPS regional inspectors, and technical specialists from headquarters will conduct integrity management program inspections. In addition, OPS will contract for other technical expertise, as needed. We are also planning how best to involve state pipeline safety inspectors in the review.

We have also added requirements that an operator provide advance notice to OPS when the operator plans to use other technology (other than internal inspection or pressure test) for a baseline or continual integrity assessment or intends to justify a longer continual assessment period. (We discuss these advance notice requirements later in the document.) We determined that an advance notice requirement was necessary in certain instances to give OPS enforcement personnel additional time to review and evaluate an operator's rationale and supporting documentation.

The rule continues to require an operator to document all aspects of its integrity management program so that OPS enforcement personnel can review these documents during an inspection to determine an operator's compliance with the rule. We have clarified the language in the final rule concerning the types of documents an operator is required to maintain. Required documents include those to support decisions and analyses made, as well as modifications, justifications, deviations, variances and determinations made, and actions taken to implement and evaluate each of the required program elements. This requirement is no different from other requirements in the pipeline safety regulations that an operator maintain current maps and records of its pipeline system, maintain a procedural manual for operations, maintenance and emergencies and maintain other records of tests and inspections. In Appendix C we have provided some examples of records an operator would have to maintain for inspection. We also discuss recordkeeping requirements in greater detail later in this document in the section by section analysis (section 195.452(l)).

4. Program Implementation and Integrity Assessment Time Frames, Assessment Methods and Criteria - Proposed Sections 195.452(b)-(e)&(j)

The notice proposed that an operator develop and follow a written integrity management program within one year after the final rule's effective date. The proposed rule included a seven-year time frame for the baseline assessment, with an operator having to assess 50% of the mileage within 3.5 years, and a ten-year maximum interval for continual integrity re-assessments. The notice proposed that an operator conduct the integrity assessment by internal inspection, pressure test, or new technology that could provide equivalent protection to the other two methods.

The proposed rule disallowed use of a magnetic flux leakage or ultrasonic internal inspection device for a pipeline segment constructed of low frequency ERW pipe or lapwelded pipe susceptible to longitudinal seam failures. This was done to be consistent with current requirements in section 195.303 providing that an operator's program for testing a pipeline on risk-based criteria provide for pressure testing of a segment constructed of either of those types of pipe.

The notice also proposed allowing as a baseline assessment an integrity assessment that an operator had conducted within five years prior to the effective date of a final rule.

The proposed rule permitted an operator to choose between two options in establishing baseline and continual assessment schedules. The first option specified risk factors to use in establishing the schedule. The second option permitted an operator to base the schedule on risk factors the operator considered essential in risk or consequence evaluation. This option would have given an operator some flexibility to establish re-assessment intervals exceeding ten years.

Implementation

API recommended that program implementation be keyed to OPS making available to operators a complete set of maps designating the high consequence areas rather than to the final rule's effective date.

The National Pipeline Reform Coalition objected to the one-year program development period based on OPS's estimate in its cost/benefit analysis of how long it would take an operator to develop an integrity management program. OPS had estimated 430 hours.

Assessment Time Frames

API and the industry commenters suggested that OPS establish January 1, 1995 as the cut off date for acceptability of prior integrity assessments, rather than tying the cutoff date to a final rule date. Enbridge and Lakehead asked that operators be allowed to justify older assessments, rather than OPS arbitrarily excluding those older than five years.

API also said that the proposed seven-year baseline and ten-year re-assessment periods were reasonable, and would allow operators to make decisions based on the characteristics of their pipeline system. The hazardous liquid operators re-iterated and concurred with API's comments.

Advocacy and environmental groups, and other commenters objected to the proposed seven-year baseline assessment and ten-year re-assessment periods. Some also objected to allowing a five-year old prior assessment to satisfy the baseline assessment. Environmental Defense suggested a three-year maximum, only allowing baseline assessments that have occurred within two years of the rule. For the continual re-assessment interval, Environmental Defense recommended that OPS follow the California model, and require re-assessment every five years. The City of Bellingham suggested that baseline assessments should be completed in one to three years, and periodic updates within five years. Fuel Safe Washington objected to allowing any prior baseline assessments, and suggested that baseline assessment be completed within 18 months, and that re-assessment be required at a maximum of five years, three years for pipelines constructed prior to 1970, and one year for pipelines located in unusually sensitive environmental areas. Pipeline Survivor's Association argued that baseline assessments should be completed in three years, with 50% of that mileage being assessed in 18 months, prior assessments be limited to one year before the rule, and re-assessments intervals be shortened to five years. The City of Austin recommended five years for establishing the baseline, 2.5 years to complete 50% of the baseline, and five years for reassessment. Batten & Associates recommended a baseline assessment period of three years, limiting prior allowable integrity assessments to one year before the rule's effective date, and re-assessment intervals of three years. LCRA recommended a seven-year time frame for completing the baseline integrity assessment and shortening the ten-year time frame for re-assessment in some instances based on pipeline-specific risk factors (e.g., age of pipe, leak history, etc.).

Several federal agencies also objected to the proposed integrity assessment time frames. NTSB urged us to reduce the period for the baseline assessment because it could not find sufficient data in the proposed rule to justify the seven-year period. EPA Oil Program Center suggested a five-year time frame for completing the baseline, with 50% of the mileage completed within 30 months. EPA Region III also recommended a five-year continual assessment period because it would provide useful integrity/deterioration information, without imposing too great a burden. DOJ/ENRD raised concern with the proposed seven-year baseline and ten-year continual assessment intervals and strongly recommended shorter baseline and continual integrity assessment intervals. DOJ/ENRD said OPS could not demonstrate that defects would not propagate to failure within the proposed seven-year period. DOJ/ENRD also questioned the basis for OPS's assumption that a ten-year interval was reasonable if a pipeline was adequately cathodically protected.

Assessment Schedule Criteria

The City of Austin recommended eliminating Option 2 - allowing an operator to establish an assessment schedule based on factors it determines essential - because it would not be feasible for an operator to demonstrate "an equivalent level of safety and environmental protection as Option 1 given the extremely complex inter-workings of the many potential risk factors." The advocacy groups argued for dropping Option 2 from the rule because it provided the operator too much discretion. EPA Region III also stated that Option 2 may provide "too loose a regimen" and supported the approach

described in Option 1. Environmental Defense preferred "a modified Option 1 in which operators could identify and report any additional risk factors to those specified in the rule." The National Pipeline Reform Coalition also recommended eliminating Option 2 because Option 1 allowed enough flexibility for an operator to determine that a specified risk factor had little or no applicability to its operations and discount the factor.

Several commenters suggested risk factors that the rule require for establishing assessment frequency. NTSB recommended that OPS not let an operator determine what factors are essential for ensuring a pipeline system's safety and environmental protection; rather the rule should specify minimum factors that an operator must consider in establishing an assessment schedule. NTSB suggested these factors include the results from previous inspections, the pipeline's leak history, material and coating conditions, cathodic protection history, type of pipe seams, product transported, operating pipe stress levels, defect types and sizes detectable by the inspection method used, defect growth rates, and effectiveness of actions taken to correct chronic problems, such as corrosion. EPA Region III suggested that risk factors for establishing frequency of assessment should also include, product specific differences, location related to the ability of the operator to detect and respond to a leak (e.g., pipelines deep underground) and non-standard or other than recognized pipeline installations (e.g., horizontal directional drilling).

National Pipeline Reform Coalition suggested risk factors such as pipe material and manufacturing processes, highly corrosive soils, and highly volatile products being transported. Dynegy suggested that highly volatile liquids not be treated as other hazardous liquids because they do not pose the same potential for damage to sensitive environmental areas. SEFBO recommended that the rule distinguish overhead suspension pipeline bridges from other above ground pipeline support structures because more sophisticated skills and experience are required to inspect and maintain cable structures. Sen. Breaux also urged that we address the role of these bridges in high consequence areas.

Assessment Methods

API expressed satisfaction that the proposed rule not only recognized that internal inspection tools provide valuable information but also recognized that a single tool or integrity assessment methodology is not always the answer, and that integrity can be assessed by various inspection methods. API and Equilon, however, suggested that we delete the footnote in the proposed rule preventing operators from using magnetic flux or ultrasonic internal inspection tools on low frequency electric resistance (ERW) welded pipe. API suggested language to ensure that the integrity of ERW seams is adequately assessed. Colonial Pipeline was pleased that the rule recognized the value of internal inspection technology and recognized that technology is constantly evolving.

Koch suggested that the rule allow an alternative assessment methodology in situations where it would be appropriate to conduct an assessment by means other than internal inspection, pressure test, or equivalent new technology. Peoples Energy questioned why the proposed rule did not allow for use of current technology, such as sonic or optical methods, that could be made feasible for pipelines.

Dynegy pointed out that a leak during a hydrostatic test could damage the environment and that installing magnets needed for instrumented internal inspection could also damage an area.

Response:

Implementation

The final rule keeps the one-year period from the rule's effective date for an operator to develop an integrity management program. (Because implementation is contingent on identifying unusually sensitive environmental areas, we are making this rule effective 60 days from when the final rule defining USAs is published.) However, the rule now requires that an operator identify all pipeline segments that could affect high consequence areas within nine months from the rule's effective date. Although implicit that an operator would have to identify the pipeline segments that were covered by the rule, the proposed rule did not propose that an operator do this. Because identification is a necessary first step in the integrity management process, we did not think it unreasonable to make it an explicit requirement.

We have also clarified that during the first year an operator must develop a program framework that addresses each element of the integrity management program. The rule further clarifies that a program begins with the initial framework. Once the program framework is developed, an operator will then have to implement and follow the program. Because an integrity management program is dynamic, the rule provides that an operator must also continually change the program as the operator gains experience.

Assessment Intervals

We have not revised the time period for an operator to conduct a baseline assessment. OPS believes that a seven-year baseline integrity assessment cycle will result in a higher quality integrity assessment and analysis of the assessment results to better ensure the integrity of each pipeline segment. Further, OPS believes that this schedule will effectively double the rate of assessment currently being conducted. Finally, we decided not to establish a shorter baseline interval because an analysis OPS conducted found that internal inspection resources needed to meet demand for baseline assessment are marginally adequate until the year 2007. This finding took into account resources that will be needed concurrently for other assessments (apart from those this rule requires.) (See memorandum from Noel Duckworth, dated October 1, 2000. This memorandum is in the docket.) We expect that internal inspection will be the primary choice of operators. Moreover, once we establish similar integrity management program requirements for liquid operators with smaller operations and for natural gas operators, these operators will all be drawing on the same market of vendors. Thus, to ensure that operators have adequate time to conduct high quality integrity assessments and to analyze the results from the assessments, we have kept the seven-year baseline interval.

Moreover, to ensure that the highest risk pipe is assessed early in the cycle, we have clarified that an operator must assess at least 50% of the pipe, beginning with the highest risk pipe, in the first 3.5 years of the seven-year baseline period. This requirement, coupled with the requirement to base the assessment intervals on risk-based factors and analyses, should ensure that an operator assesses the highest risk segments in a shorter time frame. An operator's schedule and rationale for establishing the assessment intervals are subject to review during an inspection.

The rule continues to allow as a baseline assessment an integrity assessment that an operator has conducted five years before the rule's effective date. However, we have revised the rule so that if an operator chooses to use a prior integrity assessment, the operator must then re-assess the pipe segment according to the continual integrity re-assessment requirements (discussed below). We believe that some operators will opt for using a prior integrity assessment to address integrity issues on a pipeline segment that need prioritized remedial action.

One of the greatest concerns expressed by Federal government agencies, environmental groups and other advocacy groups (as discussed above) was that the proposed ten-year continual re-assessment interval was too long to ensure public safety and environmental protection. Because of the concern expressed, we did additional research and reconsidered the issue. Based on what we found, we have revised the final rule to shorten the continual re-assessment interval. The rule now requires an operator to establish intervals not to exceed five (5) years for continually assessing the line pipe's integrity, unless the operator can demonstrate that one of the limited exceptions applies.

In deciding on the five-year interval, we relied extensively on an analysis OPS conducted on internal inspection devices (Noel Duckworth memorandum dated October 1, 2000). The analysis is available in the docket. The analysis found that, in 1999, the three major internal inspection devices vendors in the U.S. logged 30,000 miles, at 68% utilization capacity, and in 2000, the vendors expect to log 45,000 miles at 90% utilization (maximum attainable). According to the memorandum, the analyst estimated that the total capacity of these three internal inspection device vendors would likely increase to about 87,000 miles by 2007. Our current estimates indicate that this rule is likely to apply to 35,500 miles of hazardous liquid pipeline. (Because of the location of pig launchers and receptors, which are typically located near pump stations 50 miles apart, operators will be internally inspecting more than the 35,500 miles of hazardous liquid pipeline required under the rule. We expect that at least 25-30% additional mileage or 44,375 miles will be internally inspected.) Additional internal inspection requirements will also be generated by future rules that will apply to smaller hazardous liquid operators and to natural gas operators. Therefore, according to the Duckworth memorandum, the three big vendors should be able to meet the demand for internal inspection devices, although demand will stress the capacity of the market. The memorandum noted that more is involved in integrity assessment than just running the internal inspection devices, and analyzing the data, but also about the planning/scheduling process between internal inspection tool companies and pipeline operators. Based on these findings, coupled with the insistent urging of several federal agencies (DOJ, NTSB, and EPA), and many other commenters, who argued that a shorter continual integrity re-assessment interval was essential to protect public safety and the environment, we have reduced the re-assessment interval to a general requirement of five years, providing for exceptions.

The five-year integrity re-assessment period is not absolute. The rule allows variance in limited instances from the five-year period: when there is an engineering basis for a longer period or when the best technology needed to assess the segment is temporarily unavailable. For example, an operator may be able to justify an engineering basis for a longer assessment interval on a segment of line pipe, if the operator can support the justification by a reliable engineering evaluation combined with the use of other technology, such as external monitoring technologies, that provides an equivalent understanding of the condition of the line pipe. Or an operator may require a longer assessment period for a segment of line pipe because the best assessment technology, given the risk factors of the segment, is not available. An operator would then have to justify the reasons why it could not comply with the required assessment period and also demonstrate the actions it is taking to evaluate the integrity of the pipeline segment in the interim. In either instance, an operator would have to notify OPS before the end of the five-year period that the operator will be justifying a longer period. If the justification is based on engineering reasons, the operator must provide nine months notice before the end of the five-years. For unavailable technology, the operator must provide 90-days notice. Advance notice will give OPS sufficient lead time to review an operator's justification and supporting documents.

The rule continues to require that an operator base both the baseline and continual assessment intervals on the risk the pipeline segment poses to the high consequence area. To establish the assessment intervals, the rule requires that an operator use specified risk factors, the analysis of the results from the last integrity assessment, and information from the integration analyses. These factors and information will help the operator to prioritize the pipeline segments for assessment.

OPS inspectors will carefully evaluate each operator's methodology for determining the baseline and continual integrity assessment schedules to ensure that the highest risk segments are being addressed in the earliest time frames. OPS inspectors will also review an operator's justification for deviating from the required five-year re-assessment interval. We have added the requirement for advance notice to OPS when an operator may vary from the five-year interval so that OPS inspectors have adequate time to review and evaluate the justification supporting the variance.

Assessment Criteria

We agree that appropriate flexibility for establishing an assessment schedule based on risk factors can be achieved by modifying Option 1 and deleting Option 2. The final rule requires that an operator base its integrity assessment schedule on all risk factors that reflect the risk conditions on the pipeline segment. The rule also specifies certain factors that an operator must consider. These factors include those we proposed in the NPRM plus others suggested by NTSB, EPA, the THLPSSC and other commenters. However, the rule does not preclude an operator from including other risk factors specific to the pipeline being assessed. OPS wants to encourage operators to supplement the specified risk factors with factors relevant to the pipeline segment being assessed.

We have not changed the final rule to establish separate requirements for highly volatile liquids and other hazardous liquids, or for overhead suspension pipeline bridges. However, because highly volatile liquids and overhead suspension bridge pipelines may pose unique risks to a high consequence area, an operator's integrity management program must consider and address these risks. In the rule, we have added pipeline suspension bridges and product transported to the list of factors an operator must consider when establishing an assessment schedule. The Appendix provides an operator further guidance on establishing integrity assessment intervals.

Assessment Methods

The rule continues to allow a choice in the integrity assessment method - internal inspection tool, pressure test, or other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe. We did not provide for another assessment method in lieu of the three permitted methods. We believe that the three permitted methods give an operator sufficient flexibility to conduct integrity assessments appropriate to each pipeline segment that must be assessed.

The rule provides that an operator choosing assessment by internal inspection must use a tool or tools capable of detecting corrosion and deformation anomalies, including dents, gouges and grooves.

We have revised the rule to delete the footnote about not using a magnetic flux leakage or ultrasonic internal inspection tool on ERW pipe. We recognize that technology in the internal inspection industry has been changing rapidly. Now, there are readily available tools, for example, ultrasonic (shear wave) and circumferential magnetic flux leakage tools, that can detect longitudinal seam failures. Therefore, the rule now allows an operator to use integrity assessment methods on ERW pipe and on lapwelded pipe susceptible to longitudinal seam failures that can assess seam integrity and can detect corrosion and deformation anomalies. An operator's integrity management program would also have to address the special risks of these types of pipe.

In the final rule we clarified that a pressure test must be conducted according to the requirements for pressure testing found in Part 195, subpart E. An operator choosing to assess by pressure test should also evaluate its corrosion control program before deciding on this option.

OPS inspectors will review the operator's selection of assessment methods for the relevant pipeline segments. OPS personnel will particularly look at the adequacy of the operator's corrosion control program when evaluating an operator's choice to pressure test.

We used the term new technology in the proposed rule as an operator's third option. In the final rule, we changed that term to other technology. Other technology would include new or existing technology that is adapted for pipeline use and provides an equivalent understanding of the condition of the line pipe as the other two methods. We have also changed the language that the other technology must provide an equivalent level of protection in assessing the integrity of the line pipe to that it must provide an equivalent understanding of the line pipe. We believe this language better reflects what an assessment tool does i.e., it does not protect the pipe but gives the operator an understanding of the condition of the line pipe.

If an operator chooses other technology as its assessment method, the operator must notify OPS 90 days before using the technology so that OPS has adequate time to review the technology.

5. Applicability (Coverage) of the Rule - Proposed Section 195.452(a)

The proposed rule applied to operators that operate 500 or more miles of hazardous liquid pipeline used in transportation. If an operator fell into that category it would then have to develop an integrity management program for all segments of pipeline that could affect a high consequence area.

EPA Oil Program Center, the National Pipeline Reform Coalition, and other advocates suggested that this rule should apply to all hazardous liquid pipelines. EPA Oil Program Center expressed confusion about whether the rule applied only to pipelines that were 500 miles long or longer. The City of Austin pointed out that smaller operators might be more likely to have poorer maintenance and operating practices. BP Amoco also urged OPS to require all hazardous liquid operators to comply with the proposed rule, expressing concerns that pipeline companies might structure their operations in a manner to avoid applicability of the rule.

NTSB suggested that integrity management requirements should apply to hazardous liquid pipelines no matter where they are located, not just those pipeline segments that could affect high consequence areas.

API and the individual operators commented on the need for greater clarity in the portions of a pipeline facility to which the rule would apply. These commenters said that OPS needed to clarify whether the integrity management program requirements were limited to the line pipe or were intended to cover other facilities included in the definition of pipeline (e.g.,pump stations, valves, breakout tanks). The pipeline industry commenters suggested that the rule be limited to the line pipe and that we address integrity issues for the other pipeline facilities in a separate rulemaking.

API also suggested that the final rule clarify that it is limited to onshore pipeline systems, and that OPS conduct a separate rulemaking on integrity management for offshore pipeline systems. API, and other industry commenters, explained that offshore lines may not be capable of accommodating internal inspection devices. API also noted that offshore pipelines pose different risks from onshore pipelines. BP Amoco thought it appropriate to include only offshore pipelines that could affect USAs in an integrity management program because offshore operations pose a limited, if any, risk to public safety. The company listed technical factors that should be considered in establishing integrity requirements for these lines. Chevron also noted that offshore lines present technical and configurational differences from onshore lines.

SEFBO and Sen. Breaux commented that the rule should clearly distinguish overhead suspension pipeline bridges because of the different skills and experience required for inspection and maintenance of such structures. Dynegy recommended that the rule exempt highly volatile liquid product pipelines that traverse wet or flooded areas, instead, that we cover those lines under the gas integrity management program rule.

Response:

The final rule clarifies that it applies to each operator who owns or operates a total of 500 or more miles of pipeline used in hazardous liquid transportation. If an operator has 500 or more miles of pipeline in its system, then the operator's integrity management program must address the risks on each pipeline segment in its system that could affect a high consequence area. The length of an individual pipeline segment that could affect the high consequence area is irrelevant to whether it is covered.

Moreover, as we explained in the NPRM, we have no intention of excluding hazardous liquid operators with smaller operations. Our public discussions had given us ample information to proceed with a proposed rulemaking aimed at larger liquid operators. While we proceeded with the first part of the rulemaking (liquid operators owning or operating 500 or more miles of pipeline), we continued to obtain further information about smaller liquid operations so that we could propose integrity management program requirements applicable to those systems. The next step in our series of rulemakings that will ultimately require all regulated pipeline operators to have integrity management programs is to propose integrity management program requirements for hazardous liquid operators who own or operate less than 500 miles of pipeline.

In this rulemaking we have not extended the pipeline integrity requirements to pipelines beyond those that could affect a high consequence area. We continue to focus on pipeline segments that could affect the areas we define as high consequence areas: populated areas, unusually sensitive environmental areas and commercially navigable waterways. However, we expect that many of the measures the rule requires for pipeline segments that could affect high consequence areas will benefit other parts of the pipeline system not covered by the rule. For example, the final rule requires an operator to analyze and integrate various information about the integrity of the entire pipeline. This analysis is likely to benefit other segments of the pipeline system. The additional preventive and mitigative measures that an operator must take to protect the high consequence area should also yield benefits beyond the segment in the critical area.

Because of the location of launchers and receivers on a pipeline, an assessment by internal inspection is likely to benefit an additional 25-30% of pipeline beyond that covered by this rule. An operator may also choose to extend the integrity assessment beyond the pipeline segment that could affect the high consequence area.

The final rule clarifies the pipeline facilities covered by the integrity management program requirements. The integrity management program requirements apply to each pipeline segment that could affect the high consequence area. We are using the term pipeline as it defined in §195.2; the term includes, but is not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, metering and delivery stations, and breakout tanks. Integrity management addresses more than material issues in line pipe, but other issues such as adequacy of procedures, operator training, and other issues related to the pipeline facilities.

The rule clarifies that the baseline integrity assessment, which involves internal inspection, pressure test, or other equivalent technology applies only to the line pipe. (Line pipe is defined in § 195.2.) The continual integrity assessments, done at intervals not to exceed five years, also are limited to the line pipe.

The continual evaluation and information analysis requirements, however, apply to the entire pipeline. To ensure that a high consequence area receives broad protection, an operator must evaluate all threats to and from the pipeline, and consider how operating experience in other locations on the pipeline could be relevant to a segment that could affect a high consequence area. Thus, the rule requires an operator to periodically evaluate the integrity of each pipeline segment that could affect a high consequence area by analyzing all available information about the entire pipeline. This information would include information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage prevention activities, and development or planned development along the pipeline segment; information about how a failure would affect location of water intake; and information gathered in conjunction with other inspections, tests, surveillance and patrols required in Part 195, including, corrosion control monitoring and cathodic protection surveys. This information analysis will be done in conjunction with the periodic evaluation and continual integrity assessment of each pipeline segment.

The rule does not apply to all offshore pipelines, only to those offshore pipeline segments (and onshore pipeline segments) that could affect a high consequence area. Offshore pipelines could, particularly, affect unusually sensitive environmental areas (USAs) and commercially navigable waterways. We are including these offshore pipeline segments because of their potential to impair unusually sensitive ecological resources, to disrupt the flow of goods to communities, or to impair unusually sensitive drinking water resources. We discuss later in this document all areas that are included as high consequence areas. (See discussion under topic heading "Definition of High Consequence Areas.") We also explain how these areas will be shown on the National Pipeline Mapping System (NPMS).

We have also added offshore pipelines to the list in Appendix C of risk factors that an operator should consider in establishing an integrity assessment schedule. Generally, risks associated with offshore lines are because of climatic or geological factors.

We did not accept the recommendation to exempt highly volatile liquid (HVL) product pipelines from this rule. (HVLs are covered under Part 195 because they are and behave like hazardous liquids when transported by pipeline under pressure.) Rather, as discussed previously in this document, we have added highly volatile liquids (or product transported) and pipeline suspension bridges to the list of risk factors an operator must consider in establishing an integrity assessment interval. And as we discuss later in the document, these factors have also been added to the specified factors an operator must consider when analyzing the need for additional protective measures for the pipeline segment.

6. Consensus Standard on pipeline integrity

In the NPRM, OPS mentioned that API was sponsoring an American National Standards Institute (ANSI) work group to develop a consensus standard on integrity management. We said that we expected the consensus standard would provide detailed guidance to operators developing and implementing an integrity management program. We further said that once the standard was final, we would consider adopting it into the integrity management rule, but only after we had provided a public notice and comment period prior to incorporating it into the rule. The work group is continuing its work on the standard and is seeking comment on the draft of the standard.

There was a difference of opinion among commenters concerning an industry group's role in coordinating the development of a standard. Environmental Defense and other public advocates, expressed concern over API's role, and suggested use of a neutral engineering society. The City of Austin urged RSPA to develop standards using a team of stakeholders that includes the regulated community, local officials, experienced safety engineers, and other appropriate experts.

API responded that the standard is being developed using the procedures of the American National Standards Institute and includes broad participation from operators, vendors, representatives from the American Society of Mechanical Engineers (ASME), the National Association of Corrosion Engineers, OPS, and pipeline safety advocates.

EPA Region III said that the pursuit of an industry consensus standard by both the API and OPS is encouraging, but asked about the direct involvement in that process by OPS and other federal agencies, and the current review procedures for such standards.

Response:

The standard being developed will be a consensus standard of the American National Standards Institute (ANSI), developed using the standard development procedures of this independent organization. The work group of technical experts includes representatives from government, industry, and members of the American Society of Mechanical Engineers (ASME). When the work group was created in February 2000, environmental and other advocacy groups were invited to join the work group.

The work group's meetings are open to the public. Public participation has been encouraged. Minutes of the meetings have been posted on OPS's website. The resulting draft standard is being distributed for public comment before publishing, allowing input and review from all stakeholders.

The Executive Committee of ASME B31.4 has also agreed, at OPS's request, to undertake a peer review of this ANSI standard to ensure that the standard adequately addresses the regulatory requirements. The ASME Executive Committee is expected to complete this peer review during fall 2000.

Accordingly, we believe that the on-going standard development process has the appropriate and adequate checks and balances built in to produce a technically sound product that can support the development and implementation of high quality integrity management programs. We expect this standard will provide more detailed guidance to operators on the specific elements and acceptable processes of an integrity management program, and can supplement the performance-based portions of the rule. Once the consensus standard is final, we will consider adopting, all or part of it into this final rule. However, we will only do so after we have provided for public notice and comment.

7. Definition of High Consequence Areas - Proposed Section 195.450

The proposed rule's definition of high consequence areas had three components: populated areas, areas unusually sensitive to environmental damage and commercially navigable waterways.

Populated Areas

The notice proposed that populated areas consist of high population areas and other populated areas. The proposed rule based these areas on Census Bureau definitions.

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

USAs

The environmental component of the proposed high consequence area definition used OPS's recently proposed definition of Unusually Sensitive Areas (USAs) (64 FR 73464; Dec. 30, 1999).

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

Commercially navigable waterways

API and liquid operators questioned the inclusion of commercially navigable waterways into the high consequence area definition. API pointed out that Congress required OPS to identify hazardous liquid pipelines that cross waters where a substantial likelihood of commercial navigation exists and once identified, issue standards, if necessary, requiring periodic inspection of the pipelines in these areas. API said that OPS had not determined the necessity for including these waterways in areas that trigger additional integrity protections. BP Amoco said the rule should be limited to protection of public safety, rather than commercial interests. Enbridge and Lakehead also questioned why waterways that were not otherwise unusually environmentally sensitive should be included for protection.

EPA Region III said that we should also consider recreational and waterways other than those for commercial use. Environmental Defense, Batten, City of Austin and others commented that we should consider all navigable waterways as high consequence areas, because of the environmental consequences a hazardous liquid release could have on such waters.

Other areas

EPA Region III maintained that product specific differences should be incorporated into the definition. Environmental Defense, Batten and other commenters wanted OPS to expand the definition of high consequence areas to include cultural, recreational, tribal and economic resources. Environmental Defense suggested we include national parks, wilderness areas, and wildlife refuges. The City of Bellingham asked that we consider addressing integrity management programs for pipeline located outside the high consequence areas.

The City of Austin commented that the definition failed to include areas that are of high consequence due to preservation or recreational value alone. The City suggested including all state, national, and local parkland, refuges and wilderness areas, and preserves designated for water quality protection and wildlife.

API argued against expanding the definition to include cultural resources, environmental resources other than those identified as USAs, and other areas of national importance. They argued that including these areas would dilute available resources and focus from the populated and environmental areas that need greater protection, and that many other Federal, state, and local regulations are in place to minimize the effects of hazardous liquid pipelines on these other areas.

During discussions with representatives from DOJ/ENRD, DOI, and EPA, we were strongly urged to include other areas as high consequence areas: all waters of the United States, wetlands and wildlife refuges, wilderness areas, fish hatcheries, units of the National Park System, and wild and scenic rivers. DOI, DOJ and EPA strongly recommended that the National Parks and National Fish Hatcheries be included in the definition.

Identification of high consequence areas

API and liquid operators wanted OPS to clarify its commitment to identify high consequence areas, to generate and publish maps of the areas, and to periodically update the maps. These commenters said that such information was necessary before operators could assess pipelines and take appropriate preventive and mitigative measures.

Response: The final rule continues to focus on areas where we have determined a hazardous liquid pipeline failure could pose the greatest threat to public safety, unusually sensitive environmental areas (including drinking water and ecological resources), and water commerce that is essential for communities' safety and public health or for national security. We have not revised the definition to incorporate product-specific differences; rather, other parts of the rule address the risks associated with different products the pipeline is transporting (e.g., when considering risk factors for establishing assessment intervals).

Populated areas

In the final rule, we have not changed the definition of populated areas that is based on the Census Bureau's definitions and delineations. We disagree that we misstated the Census Bureau's definition of urbanized areas. The only change we have made is in the terms we are using. What Census Bureau calls an urbanized area, we are calling a high population area. The additional populated areas that the Census Bureau calls a census designated place, we are calling an other populated area. We have chosen these definitions to avoid confusion over the term places, which the Census Bureau uses to include both urbanized and census designated places. Our National Pipeline Mapping System (NPMS) will use the same titles and definitions used in this final rule.

We are using Census Bureau data for the population component because it is the recognized expert and source for general population data in the communities of the United States. The data are standardized, publicly available and in a format that allows OPS and others to create maps of the populated areas. OPS currently does not have the resources to gather local data on utility connections. However, nothing precludes an operator from supplementing the maps we will provide with other data pertinent to its pipeline. (As discussed later in this Preamble under the sub-topic heading "Identification of high consequence areas", an operator will have the ongoing responsibility to incorporate newly-identified populated areas and unusually sensitive environmental areas into its assessment plan.)

Populated areas consist of high population and other populated areas. High population areas are the Census Bureau's urbanized areas. These areas contain 50,000 or more people and have a population density of at least 1,000 people per square mile. Other populated areas are the Census Bureau's places minus the urbanized areas. These areas contain concentrations of people and include incorporated or unincorporated cities, towns, villages, or other designated residential or commercial areas.

We believe the population component of the high consequence area definition picks up most areas where pipelines can pose a threat to public safety. However, we are aware that there may be other areas where people congregate near pipelines, but do not fall within either sub-component of the population definition. Two recent and tragic accidents illustrate the dangers that pipelines pose to public safety in these areas. In Bellingham, Washington, a pipeline release into a creek ignited and resulted in the deaths of three young people who were in the recreational park through which the creek flowed. An explosion that occurred on one of three adjacent large natural gas pipelines near Carlsbad, New Mexico, killed 12 people, including five children, who had been camping near the pipeline.

Although this rule is not including areas where people congregate in the high consequence area definition, OPS is considering addressing these areas in a future rulemaking. In the meantime we encourage operators to consider addressing in their integrity management programs areas where people congregate and to determine if there are pipeline segments in or near these areas that could affect the area. Operators should be able to recognize these areas, through fly overs or other surveillance made of their pipelines, or through consultation with local officials in the community.

USAs

The rule's definition of high consequence areas will incorporate the final definition of Unusually Sensitive Areas, which OPS expects to issue in November 2000 (Docket No. RSPA-99-5455). The USA rulemaking will address the resolution of the above comments and others submitted to the docket for that rulemaking. Because the dependence of this rulemaking on the final definition of USAs, this rule will not be effective until 60 days after the final USA rule is published.

Commercially navigable waterways

Our inclusion of commercially navigable waterways for public safety and secondary reasons is not based on the ecological sensitivity of these waterways. Parts of waterways sensitive for ecological purposes are covered in the proposed USA definition, to the extent that they contain occurrences of a threatened and endangered species, critically imperiled or imperiled species, depleted marine mammal, depleted multi-species area, Western Hemispheric Shorebird Reserve Network or Ramsar site. In this rule, only those pipeline segments that could affect a commercially navigable waterway are covered. We are including commercially navigable waterways as high consequence areas because these waterways are a major means of commercial transportation, are critical to interstate and foreign commerce, supply vital resources to many American communities, and are part of a national defense system. A pipeline release could have significant consequences on such vital areas by interrupting supply operations due to potentially long response and recovery operations that occur with hazardous liquid spills. As explained later, OPS will map these waterways on its National Pipeline Mapping System.

Other areas

As discussed above, representatives of several Federal government agencies urged us to include other areas in the definition of high consequence areas. We have decided not to include these suggested areas in this rulemaking.

Although we have not included the other suggested areas in this rulemaking, we are considering extending protection to other environmentally sensitive and vital resources through future rulemaking. Other areas that will be considered include National Parks, National Wildlife Refuges, National Wilderness Areas, National Forests, and other cultural resources and sensitive environmental resources that do not meet the USA filtering criteria.

Identification of high consequence areas

OPS will identify high consequence areas on its National Pipeline Mapping System (NPMS). Operators, other government agencies and the public will have access to these maps through the Internet. Individuals will be able to view high consequence areas nationally or by state, county, zip code, or zooming in or out of a particular area. An operator will then be able to determine which of its pipeline segments intersect

or have the ability to affect a high consequence area.

OPS will identify the locations of USAs through a comprehensive collection and analysis of drinking water and ecological resource data, contingent on the availability of funding and resources.⁽³⁾ OPS will make its USA maps, including the drinking water data, available through the National Pipeline Mapping System. Barring unforeseen resource demands, OPS's current plan is to have the USAs in the top ten states (covering 75% of total pipeline mileage) available by the end of December 2000. Maps of the USAs in the next ten states (90% of total pipeline mileage) should be available by April 2001. And we plan to have the maps of the remaining states(100% of total pipeline mileage) available by December 2001.

Some of the information that OPS is purchasing, such as discrete sets of ecological data from the Nature Conservancy and other sources, will not be publicly available. Operators may need to contact resource agencies to obtain additional information on a particular species or drinking water intake in an USA.

OPS will use the National Waterways Network database to identify commercially navigable waterways. The commercially navigable waterways map and database will be available through the National Pipeline Mapping System. The Bureau of Transportation Statistics also has a database that includes commercially navigable waterways and non-commercially navigable waterways. The database can be downloaded from the BTS website: http://www.bts.gov/gis/ntatlas/networks.html.

OPS will use the Census Bureau's data to identify high population and other populated areas. We will use the Census Bureau's urbanized area data to identify high population areas and their places data to identify other populated areas. Their data on places includes both urbanized areas and other populated areas. OPS will filter out the urbanized areas data from the places data so that the resulting map and database will clearly distinguish other populated areas from the urbanized or high population area data. Operators and the public will be able to view the high population and other populated areas maps together or separately on the National Pipeline Mapping System.

OPS recognizes that inventories and maps of high consequence areas have to be updated on a periodic basis to incorporate new information and databases. OPS intends to update the high consequence area maps every five years, contingent on the availability of funding and resources. OPS will review new or revised programs and databases at that time to incorporate appropriate programs and databases into the high consequence area definition and model. OPS will announce in the federal register and through other communication networks when revised high consequence area maps are available for given areas.

Changes, particularly population changes, will occur around an operator's pipeline. Although OPS intends to periodically update the maps, it remains an operator's responsibility to keep information about its pipelines up to date. By continually evaluating its entire pipeline and analyzing all available information about the integrity of the pipeline, an operator should be aware of population and ecological changes that are occurring around the pipeline and continue to update its maps and integrity management program to accommodate these changes.

In the rule we have added requirements about how an operator is to incorporate any newly-identified high consequence areas into its baseline assessment plan and integrity program. The rule provides that when an operator has information (from the information analysis or from Census Bureau maps) that the population density around a pipeline segment has changed so as to fall within the definition of a high population area or other populated area, the operator must incorporate the area into its baseline assessment plan as a high consequence area within one year from the date the area is identified. Similarly, an operator must incorporate a new unusually sensitive environmental area into its plan within one year from the date the area is identified. The rule further requires an operator to complete the baseline assessment of any line pipe that could affect the newly-identified high consequence area within five years from the date the area is identified.

We thought it necessary to add these requirements because of the concerns many commenters expressed about who would be responsible identifying high consequence areas and how updates would be handled. Although OPS is taking primary responsibility for mapping these areas, an operator has a corresponding responsibility to continually evaluate its pipeline and update information about the pipeline.

8. Requirements for Preventive and Mitigative measures, including, emergency flow restricting devices (EFRDs) and leak detection systems - Proposed Section 195.452(i)

The proposed rule required an operator to conduct a risk analysis to assess the risks to its pipeline system and determine what additional preventive and mitigative measures are needed to protect a high consequence area. The proposal identified possible preventive or mitigative measures an operator could take to protect a high consequence area, such as implementing damage prevention best practices, establishing or modifying leak detection systems, and providing additional training on response procedures.

Installing EFRDs was one of several mitigative measures the rule proposed. However, the proposal did not require an operator to install EFRDs or define the conditions under which an operator should install EFRDs. In the NPRM we specifically invited comment on any needed further guidance to operators on when EFRDs should be installed. We also invited comment on the criteria for evaluating the decision on whether to install an EFRD or to take other measures, and if in certain limited circumstances, we should mandate the use of EFRDs.

EPA Region III supported the preventive and mitigative measures the rule proposed but argued against leaving the need for particular actions to the operator. Region III was concerned that without active and knowledgeable regulatory oversight, strict methodology, or the required participation of a risk assessment professional, an operator would be unlikely to find any of the measures necessary. Environmental Defense said that the rule should include specific requirements for operators to use preventive strategies. NTSB expressed concern with operators using risk management principles to determine the need for additional protective measures and recommended that the rule include minimum criteria.

EPA Oil Program Center said that the rule should prescribe circumstances in which EFRDs or other protective and mitigative measures must be used. EPA Oil Programs further commented that if the rule allows an operator to conduct a risk assessment to determine if EFRDs or other protective measures are needed, then the rule should prescribe a specific risk assessment protocol.

Environmental Defense, Batten and other advocates recommended that the rule include performance standards for leak detection, EFRD spacing and damage prevention best practices. Environmental Defense and Pipeline Survivor's Association recommended that leak detection systems be capable of detecting a leak of one gallon/minute or more and that EFRD spacing prevent releases of more than 10,000 gallons of hazardous liquid into a high consequence area. The City of Austin supported requiring EFRDs in all high consequence areas and that they be spaced to restrict the worst case spill to 10,000 gallons. Batten suggested that leak detection devices be capable of detecting within 15 minutes a leak of ten gallons or more and that pipe segments between EFRDs be able to contain no more than 50,000 gallons when located in a high consequence area.

AWWA encouraged the placement of EFRDs to the greatest extent possible to protect public water supplies, suggesting that EFRDs be used as the standard against which other mitigation strategies are measured. LCRA commented that EFRDs should be required on either side of a river crossing. EPA Region III also encouraged using EFRDs whenever necessary to protect a high consequence area.

API and operators commented that the proposed rule is reasonable and that OPS should ensure risk mitigation decisions made within an integrity management program include considering the use of EFRDs rather than requiring such placement or prescribing minimum spacing. Enbridge and Lakehead supported EFRDs as one of various preventive or mitigative actions an operator should consider but said there was no one distance or placement specification appropriate for all pipeline systems. Many cited research by the California State Fire Marshall, and Southwest Research to support their argument that there are many site and flow-specific factors that operators must consider in making risk mitigation decisions. Several industry commenters also noted the possible environmental disadvantage to EFRDs, including the possibility of valve leakage or inadvertent closure resulting in over pressurization, as well as the environmental impacts of installing and maintaining valves in or near environmentally sensitive areas.

Response: The final rule continues to require an operator to take additional measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. It is up to each operator to conduct a risk analysis of the pipeline segment to identify additional actions to enhance public safety or environmental protection. For this risk analysis, the rule clarifies that an operator must evaluate the likelihood of a pipeline release occurring, how a release could affect the high consequence area, and what risk factors the operator should consider. The rule continues to list some additional preventive and mitigative measures an operator should consider. The list is not an exhaustive recitation of every preventive or mitigative measure that could enhance public safety or environmental protection.

One of the listed measures is for an operator to modify the systems that monitor pressure and detect leaks. Operators use various procedures and methods to detect the movement of product through the pipeline. For example, computational pipeline monitoring, SCADA systems, and station sensors, measure deviations from measured values (pressures, flows) beyond established norms. The pipeline safety regulations do not require an operator to have a leak detection system. However, if an operator has a software-based leak detection system, the regulations require the operator to use an industry document (API 1130) in designing, evaluating, operating, maintaining and testing its software-based system. (See § 195.444.) Moreover, whenever a leak detection system is installed or a component replaced, API 1130 must be followed.

The final rule requires an operator to have a means to detect leaks on its pipeline system. (We provide several examples of types of leak detection systems later in this document when we discuss Section 195.452(i).) We have re-written the rule to require an operator to evaluate the leak detection's capability to protect the high consequence area and to modify, as needed, to protect the high consequence area. The rule includes factors that an operator must consider in making its evaluation. OPS enforcement personnel will review the adequacy of this evaluation process during site inspections.

Another protective measure the rule identifies is for an operator to install an EFRD on the pipeline segment. The final rule does not prescribe the specific conditions under which EFRDs or other preventive or mitigative measures are required. Rather, the final rule requires an operator to develop and apply risk assessment and decision-making processes that reflect pipeline-specific conditions and operating environments. The rule now specifies criteria that an operator must consider when conducting the analysis to identify additional protective measures. An operator is not limited to these criteria; rather, an operator must consider these criteria in addition to all other criteria specific to the pipeline segment.

In the final rule, OPS has not specified the circumstances when an operator must use a particular protective measure or install an EFRD. However, we have revised the rule to require that an operator install an EFRD if the operator determines that one is needed to protect the high consequence area. The rule also specifies factors that an operator must consider in making this determination. OPS will review during inspection the adequacy of the analysis and the appropriateness of the operator's decision on the need to install an EFRD.

OPS has been studying for some time the issue of the optimum placement of emergency flow restricting devices to limit commodity release after the location of the release has been identified. In the NPRM, we explained in detail the research OPS has conducted in this area. (See 65 FR 21695; April 24, 2000.) In addition to comment the NPRM solicited, OPS had previously issued an advance notice of proposed rulemaking asking questions concerning the performance of leak detection equipment and location of EFRDs, and held a public workshop to discuss the issues involved in developing regulations on EFRDs.

Our study of the issue led us to conclude that the decision to install an EFRD should not be mandatory but should be left to the operator. Nonetheless, the rule requires an operator to consider certain specified criteria in deciding whether an EFRD will protect the high consequence area.

OPS is requiring an operator to determine whether to install an EFRD based on the operator's risk analysis, because, we believe, prescriptive valve installation and spacing requirements would ignore the site-specific variables and unique flow characteristics of a pipeline segment. Prescriptive requirements could also overlook the potential sensitivity of a specific high consequence area. For example, locating an EFRD near a body of water to reduce the potential volume released might necessitate locating the valve in sensitive wetlands or a flood plain of a river, which creates myriad other problems. Also, a prescriptive approach detracts from the process of evaluating a host of alternative measures to enhance protection to high consequence areas.

9. Methods to measure program's effectiveness - Proposed Section 195.452(k)

In the NPRM we proposed that an operator's integrity management program include methods to measure whether the progr