U.S. DOT/RSPA - Environmental Assessment

Page 1Research and Special Programs Administration U.S. Department of Transportation Environmental Assessment Final Rule Pipeline Integrity Management in High Consequence Are 13s for Hazardous Liquid Pipeline Operators Operating Less than 500 Miles of Pipeline Docket: RSPA 00-7408#

Page 2Preliminary Finding of No Significant Impact This Environmental Assessment is prepared in accordance with section 102(2)(c) of the Natio: ial Environmental Policy Act (42 U.S.C. Section 4332), the Council on Environmental Quality regulations (40 CFR Sections 1500-1 508), and Department of Transportation Order 5610. IC, Procedures for Considering Environmental Impacts. It was prepared to assist in the Research ;md Special Programs Administration’s (RSPA) planning and decision-making. This document is an update of the original Environmental Assessment prepared in support of the proposed rule (66 FR 15821). This document concisely describes the RSPA’s final rule on integrity management in high consequence areas for certain operators of hazardous liquid pipelines. It also addresses the n a d for the proposed action, the alternative actions considered, the environment affected by this action, the consequences to the environment of the proposed action and the alternatives, and a list of the agencies and organizations consulted. This Environmental Assessment provides suffici .:nt evidence to determine that the provisions of the final rule are expected to have no significant impact on the environment. i#

Page 3Table of Contents A. A. 1 A.2 A.3 A.4 B. Purpose and Need for Action Recent RSPA Pipeline Safety and Environmental Protection Programs Legislative History and National Transportation Safety Board Recommendations Interactions with Industry, Other Agencies, and Stakeholders Future RSPA Integrity Management Initiatives 1 1 2 5 8 Description of Proposed Action 10 C. D. Alternatives Considered 14 Affected Environment 15 E. Environmental Consequences of Proposed Action and Alternatives 19 E. 1 E.l.l E. 1.2 E.1.3 E. 1.4 E. 1.5 E. 1.6 Environmental Impact of the Integrity Management Rule Overview of Internal Inspection and Pressure Testing Environmental Impacts of Internal Inspection and Pressure Testing Environmental Impacts of Baseline Integrity Assessment Requirements in Final Rule Environmental Impacts of Periodic Assessment Requirement in Final Rule Environmental Impacts of Other Preventive and Mitigative Actions Summary of Environmental Impacts for Final Rule 19 20 22 23 27 29 31 E.2 Environmental Impacts of the Altematives E.2.1 E.2.2 Take No Action Mandatory Integrity Assessment in all High Consequence Areas Every Ten Years F. Environmental Justice Considerations 33 33 34 35 G. Information Made Available to States, Local Governments, and Individuals H. List of Agencies and Persons Consulted I. Conclusion J. References Appendix 1 Environmental Impacts of Oil Spills 36 38 39 40 41 I I#

Page 4A. Purpose and Need for Action The Research and Special Programs Administration (RSPA) believes that pipeline safety regulations address the most important risks to the nation’s pipelines, and have served the industry and the nation well. The hazardous liquid pipeline industry has a good safety record compared to other modes of transportation. However, pipeline incidents still occur and, on occasion, with serious consequences. Continued improvement in safety and environmental performance is still RSPA’s highest objective. RSPA believes that safety programs based onllr on compliance with the regulations can result in a piece-meal approach to identifying and controlling risks, sometimes neglecting the relationships among different risk factors and the potential benefits of coordinated risk control activities. Having operators implement more systematic and integrated approaches to assure pipeline integrity and address the most important pipeline risks offers the greatest opportunity to improve the industry’s performance. Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In addition to the positive safety and environmental benefits, the lost product and unscheduled downtime for repairs following a major incident can significantly impact the company’s financial performance, and its ability to satisfy customer commitments. Operators can not afford to have these critical transportation assets out of service for lengthy periods of time in today’s competitive business environment. In addition, the damage to the company’s public image arid reputation, as well as the legal implications of serious incidents, can pose an even broader and longer term negative impact on the company’s business operations. For these and other reasoi is, many pipeline operators have implemented and are continuing to improve more systematic sa fety and environmental management processes. A. 1 Recent RSPA Pipeline Safety and Environmental Protection Promams To better understand and promote more comprehensive and integrated approaches to safety a id environmental protection, RSPA created the Risk Management Demonstration Program, and the System Integrity Inspection (SII) Pilot Program. These programs encourage and evaluate operator-developed safety and environmental management processes that incorporate operatc r- and pipeline-specific information and data to identify, assess, and address pipeline risks. Thtmse programs, along with the Oil Spill Response Plan Review and Exercise Program, are helping RSPA’s Office of Pipeline Safety (OPS) refine its regulatory oversight processes. These processes help to ensure that pipeline operators have effective processes in place to identify the most important risks to the public and the environment, and to develop and implement cost- effective preventive and mitigative actions to manage these risks. These initiatives have validated the importance of focusing resources and establishing higher levels of protection ir areas where a pipeline failure could have significant consequences. Through the Risk Management Demonstration Program and the System Integrity Inspection I?ilot Program, OPS has improved its understanding of pipeline operator integrity management sy:,tems and activities. This experience has shown that a number of liquid operators have formalized 1#

Page 5management systems to identify and address the most significant integrity threats to their pipelline systems. In the Risk Management Program, participants perform systematic and comprehensive risk assessments to identify the specific nature and location of the most significant risks posec by operation of their pipeline system. An essential feature of these risk assessments is the integration of information fi-om many diverse sources to fully understand the integrity threats it specific locations on the pipeline. Environmental consequences and the impact on nearby population are explicitly considered in these risk assessments. Through formal, risk-based decision making processes, these companies use the risk assessment results to identify projecl s and activities that address potential system integrity threats, thereby helping to prevent oil spi Is. The risk management process also examines the consequences of potential releases and exploires opportunities to minimize the environmental and public safety and health impacts should a failure occur. These investigative risk management programs, and the preventive and mitigative risk control activities that evolve from them, supplement the minimum regulatory requirements established in 49 CFR 195 to protect the public and the environment. The SII Program is focused on developing a more integrity-based approach to OPS inspectior s. In addition to verifying an operator's compliance with the pipeline safety regulations, OPS is focusing the inspection process on an operator's integrity management processes and activiticms. By working with the operator, OPS is able to understand and influence the methods and approaches used to integrate integrity assessment data with other pipeline specific informatio ,I to identify the most significant integrity threats to the system. Specifically, OPS has observed how operators examine in-line inspection data in conjunction with other surveillance and operatin data, expected population growth, land use, construction activity along the pipeline, and othe . information relevant to assuring the integrity of the pipeline in high population areas and in environmentally sensitive areas. Through this interaction OPS is acquiring a broader understanding and a greater confidence that effective programs are in place to address the mc st significant risks. Similar to the Risk Management Program, the SI1 Program is emphasizing liow operators evaluate their system condition and its risks, and use this information to make sour d integrity management decisions. While these two programs only involve a limited number of operators, OPS discussions with other companies in industry forums and working groups have indicated that formal integrity management programs have become more common, particularly within the liquid pipeline industry. OPS found that many liquid companies are developing more sophisticated and mal ure integrity management systems, analytical methods, data integration processes, and diagnostic: tools. OPS believes the next step is to require all operators to develop and follow at least minimum level integrity management programs. A.2 Legislative History and National Transportation Safety Board Recommendations Congress has also directed DOT to consider several initiatives that could improve safety and environmental protection, especially in locations where pipeline failures might have signific mt 2#

Page 6impacts to human health and safety and the environment. Specifically Congress has directed DOT to: Prescribe standards establishing criteria for identifying gas pipeline facilities located ii I high-density population areas, and hazardous liquid pipelines that cross waters where I substantial likelihood of commercial navigation exists, are located in high-density population area, or are located in an area unusually sensitive to environmental damage (USAs) [49 U.S.C. 4 60109(a)(2)]. Prescribe additional standards requiring the periodic inspection of pipelines in US As rind in high-density population areas. The regulations are to prescribe when an inst”enti2d internal inspection device, or similarly effective inspection method, should be used to inspect the pipeline [49 U.S.C. 4 60102(f)(2)]. 0 Survey and assess the effectiveness of emergency flow restricting devices (EFRDs) ar,d other procedures, systems, and equipment used to detect and locate hazardous liquid pipeline ruptures, and to prescribe regulations on the circumstances under which an operator of a hazardous liquid pipeline facility must use an EFRD or such other procedure, system, or equipment [49 U.S.C. 4 60102(i)]. , In addition to these Congressional directives, the National Transportation Safety Board (NTS B) has made several recommendations addressing improved protection for high population and environmentally sensitive areas. These recommendations include: 0 Requiring periodic testing and inspection to identify corrosion and other time-dependiznt pipeline damage. Establishing criteria to determine appropriate intervals for inspections and tests, inch ding safe service intervals between pressure testing. 0 Determining hazards to public safety from electric resistance welded (ERW) pipe and establishing standards for leak detection systems. Establishing requirements for installing automatic or remote-operated mainline valve s on high-pressure lines in urban and environmentally sensitive areas to provide for rapid shutdown of failed pipeline segments. RSPA has initiated several programs and activities in response to these legislative mandates and NTSB recommendations. As summarized in Section A. 1, the Risk Management and SII Pili kt Programs have provided an understanding of how these issues can be effectively addressed within the context of a comprehensive and systematic integrity management program that considers the total spectrum of risks from pipeline operation, including those risks in locatic ns where the consequences to public health and safety and the environment may be elevated. 3#

Page 7RSPA has also undertaken a rigorous and thorough process for developing the criteria to definje USAs. This multi-year process involved numerous interactions with other Federal and State agencies, representatives of the hazardous liquid pipeline industry, environmental organizatioi,is, and other stakeholders. RSPA published for public comment proposed criteria to define USA!; on December 30, 1999 (64 FR 73464). Numerous public comments were received on the proposed criteria (available in Docket # 99-5455). The proposed USA criteria were also pilot tested to confirm that the proposed USA definition can be used to identify and locate unusually sensitive drinking water and ecological resources using available data from government agencies and environmental organizations. The pilot te st identified USAs in Texas, California, and Louisiana - states with a large number of hazardou,; liquid pipelines, as well as considerable drinking water and ecological resources. The results Iof the pilot test, as well as the criteria in the proposed USA definition, were reviewed by a team of nationally recognized experts on drinking water and ecological resources. In late 2000, RSPA completed its evaluation of the feedback from the technical peer review, public comments, and the pilot test results. After extensive consultation with other Federal agencies, a final rule defining USAs was issued on December 21,2000 (65 FR 80530). RSPA evaluated the potential benefits of EFRDs in limiting the volume of product released following a hazardous liquid pipeline failure. The results were published in "Emergency Flow Restricting Devices Study" in 1991 (available in Docket # PS-133). This study recommendecl that OPS seek public input on the placement of EFRDs in urban areas, at water crossings, at other critical areas affected by commodity release, and in areas in close proximity to the public outside of urban areas. This study also concluded that remote control and check valves are tl e only effective EFRDs. In January 1994, RSPA issued an advance notice of proposed rulemaking (ANPRM) (59 FR 2802) to solicit data from the public through a series of questions primarily concerning the performance of leak detection equipment and location of EFRDs. A public workshop was hcmld in October 1995 to further address the issues associated with requiring EFRDs. These forums raised important concems about the effectiveness and cost-effectiveness of these mitigative features. It was suggested that the need for EFRDs should evolve from an integrated evaluation of the site-specific conditions and risks facing a particular pipeline location. This evaluation would include assessing the effectiveness of the existing preventive and mitigative activities as well as considering the need for additional preventive or mitigative risk control activities. Especially when considering mitigative actions like EFRDs, the environmental sensitivity of the location is an important factor that must be considered to make the best overall risk reductio 1 decisions. Thus, RSPA deferred proposing regulations requiring EFRD installation until US.Qs were defined. RSPA believes that the experience obtained through the Risk Management Demonstration Program, the SLI Pilot Program, the USA definition process, and other initiatives has providcd a foundation for moving forward with a rule that addresses these Congressional mandates and NTSB recommendations in a comprehensive and integrated manner. 4#

Page 8A.3 Interaction with Industry, Other Agencies, and Stakeholders On October 21, 1999, RSPA issued a Notice (64 FR 56725) announcing a public meeting to discuss the need for additional regulations for natural gas and hazardous liquid lines in high population areas, commercially navigable waters, and areas of the environment that are unusu:illy sensitive to the environment damage (Le., high consequence areas). This Notice included a conceptual approach to providing improved protection in high consequence areas, and solicite d feedback on a number of specific questions relative to this approach. In the Notice, RSPA sta,ted that any process for protecting high consequence areas should include: 8 Pipeline-specific assessments in determining the need for additional preventive and mitigative activities; a An assessment approach that considers all risk factors and risk reduction activities in ;In integrated manner; and a Increased assurance that high consequence areas are being protected. The public meeting was held on November 18 and 19, 1999, in Hemdon, Virginia. The prirriary discussion topics included: the key elements of an effective integrity management program, tl le extent to which operators now have integrity management programs, and how to validate the effectiveness of such programs. In addition, RSPA obtained feedback and input on a broad airay of integrity management issues, including: a How to characterize and define high consequence areas, a Key elements of operator integrity management programs, a Types of information that should be integrated to assure pipeline integrity; and a OPS review of integrity management programs, including what elements to review arid inspect. A synopsis of the feedback obtained at this meeting, as well as complete transcripts of the fo ;mal presentations are available in Docket # 99-6355, and on the OPS home page at http://ops.dot.gov. On December 22, 1999, RSPA issued a Notice in the Federal Register (64 FR 7 17 13) annoui icing an extension of the public comment period to January 17,2000. The availability of an electIonic discussion forum was announced to allow interested parties to express their views on integri y management program issues and the need for improved protection in high consequence area:,'. This Notice also referenced a draft conceptual model for assuring pipeline integrity in high consequence areas, and solicited comments on the draft approach. RSPA received commenl s from several organizations and individuals. These are available in the Docket # 99-6355, and are 5#

Page 9summarized in the preamble of the Notice of Proposed Rulemaking (NPRM) announcing the proposed requirements for integrity management programs. (65 FR 21695, April 24,2000: See additional discussion below). Following the public meeting, RSPA hosted a number of smaller meetings and conference cal s to make sure the broadest range of comments and information were considered in drafting the NPRM. Discussion items included the areas that should be considered high consequence areal;, reasonable milestones for completing benchmark testing, developing industry standards to support a rule, how a rule should acknowledge differences between the gas and liquid pipeline industries as well as among individual operators, and how best to involve affected communitii :s. These topics were discussed with Interstate Natural Gas Association of America (INGAA) representatives on January 12, American Petroleum Institute (MI) representatives on January 13, National Association of Pipeline Safety Representatives (NAPSR) on January 14, February 1 , and March 3, public interest representatives on January 19 and February 29, and the NTSB on February 8. Minutes from each of these sessions are in the Docket. After considering the feedback from the public meeting, comments to the Docket, and experimce in the Risk Management and SII programs, RSPA elected to implement integrity managemen1 requirements for the pipeline industry through a series of rules focused on different objectives. On April 24,2000, RSPA published a Notice of Proposed Rulemaking (NPRM) “Pipeline Integrity Management in High Consequence Areas” (65 CFR 21695). This proposed rule focused on the hazardous liquid industry operators who own or operate 500 or more miles of pipeline. Approximately 87% of the hazardous liquid transportation lines are operated by operators with 500 or more pipeline miles. A number of individuals and organizations provided comment on the proposed rule describec in the NPRM. These comments are available in Docket # 99-6355, and summarized in the preamble to the final rule. In addition to public input, RSPA also continued its consultations with other Federal agencies, including the Environmental Protection Agency, the Departmenl of Justice, and the Department of the Interior. Guidance was also obtained from the Technical Hazardous Liquid Pipeline Safety Standards Committee, RSPA’s statutory advisory committ ,:e for hazardous liquid pipeline safety. On December 1 , 2000, RSPA published a final rule on htegrity Management in High Consequence Areas covering Hazardous Liquid Operators wit 1 500 or More Miles of Pipeline (65 FR 75378). The key provisions of the final rule are summarized below: 0 Operators must identify pipeline segments on their systems where a release could impact a high consequence area. High consequence areas are defined as populated areas, US As, and commercially navigable waterways. 0 Operators must conduct baseline integrity assessments on pipeline segments that cou .d affect high consequence areas. Acceptable methods for assessment include internal inspection, pressure testing, or another technology that the operator demonstrates can provide an equivalent level of understanding of the pipe’s condition. Baseline 6#

Page 10assessments for these pipeline segments must be completed by March 3 I , 2008, with 5 0% of the distance assessed by September 30,2004. The highest risk segments must be assessed first. Operators must perform periodic integrity assessments on segments that could affect high consequence areas at intervals not to exceed 5 years. Operators must develop and follow a written integrity management program that consiists of the following elements: t a process for determining which pipeline segments could affect high consequei ice t b t t t areas, a Plan for conducting the baseline assessments noted above, a process for continual integrity assessment and evaluation, an analytical process that integrates all available information about pipeline integrity and the consequences of a failure, repair criteria to address issues identified by the integrity assessment method aiid data analysis (the rule provides minimum repair criteria for certain, higher risk, features identified through internal inspection, as well as time frames in which certain features must be repaired), a process to identify and evaluate preventive and mitigative measures to protecmt high consequence areas, methods to measure the integrity management program's effectiveness, and a process for review of integrity assessment results and data analysis by a qualified individual. On March 2 1,2001, RSPA issued a NPRM (66 FR 15821) to extend the same requirements 1 o protect high consequence areas and establish integrity management programs to all hazardou ,; liquid pipeline operators regulated under 49 CFR 195 (i.e., include those operating less than ,io0 miles of pipeline). An Environmental Assessment was prepared in support of this NPRM. I his final Environmental Assessment is an update of the previous work. RSPA received a small number of public comments on the NPRM. After reviewing this inpi it, as well as discussions with other Federal agencies, RSPA has decided that the same requirements for protection of high consequence areas and the development of integnty management prog ams should apply to all hazardous liquid pipeline operators. Section B of this Environmental Assessment describes these requirements. In addition to these requirements for integrity management in high consequence areas, there :are many other Federal, state, and local government regulations in place to protect sensitive resources. These include regulations to protect drinking water resources, threatened and endangered species, critical habitats for various species, and spawning areas. Areas have be.:n created and designated to protect and maintain aquatic life, wildlife, and various other naturd and water resources. Permits, environmental assessments, and consultations with resource 7#

Page 11experts are required by various Federal, state, and local agencies before a pipeline can be installed or construction to modify or repair an existing line take place. RSPA’s existing and planned future regulations complement and enhance these other Federal, state, and local government regulations on sensitive drinking water or ecological resources. A.4 Future RSPA Intea-itv Management Initiatives RSPA plans to propose additional rules on pipeline integrity management for interstate and intrastate natural gas operators in the near future. RSPA has met with representatives of CNGI,A on January 12, March 29, April 19, June 15, July 20, September 6, September 19, October 12. and December 18,2000 to discuss a variety of issues related to improved integrity manageme it for gas pipelines, including: a the definition of high consequence areas for gas pipelines; a integrity assessment technologies for gas pipelines, including “direct assessment”; e inspection fiequency; e data integration and analysis; e integrity management for low hoop stress piping; a the level of integrity assurance provided by the current regulations (including high population areas); a current company practices that go beyond the protection explicitly required in the regulations; and a fbture standards to support integrity management. On February 12 and 14, 2001 RSPA conducted a public meeting in Arlington, VA to discuss these subjects and other topics relevant to an integrity management rule for gas pipeline operators. Subsequent to the public meeting RSPA synthesized the input received, and issued a Notice to request public comment and input on integrity management concepts related to gas pipelines (June 27,2001; 66 FR 34318). This input is currently being evaluated. RSPA expticts to issue one or more proposed rules for gas pipelines beginning in late 2001. RSPA has also initiated dialog with industry and various public interest representatives to explore approaches to improve communication between OPS, pipeline operators, and the communities in which pipeline facilities are located. Initial discussions have focused on strengthening the liaison between public officials and pipeline companies, testing the usefuli less of pipeline data provided to public officials, and developing concepts for restructuring the respective roles of federal, state, and local officials, emphasizing the distinction between 8#

Page 12participation and communication. Meetings were conducted on February 28 and 29, Septemb ,:r 17, and October 10, 2000 to begin addressing the multi-faceted communication issue. During a public meeting on February 13,2001 , OPS sought additional input on enhancing communicat on with the public and local officials near pipeline facilities. RSPA is currently considering how to best improve communications between pipeline operators, the government, and local officials The specific requirements of any future proposed rules related to integrity management for natural gas pipelines and communications, and the environmental impacts associated with thc se requirements will be considered in their respective rulemaking processes. 9#

Page 13B. Description of Proposed Action On December 1, 2000, RSPA published a final rule establishing new requirements for integrit,y management in high consequence areas for operators that own or operate 500 or more miles o I pipe (65 FR 75378). RSPA is now establishing similar requirements for the remaining hazarclous liquid operators. ’ Under these requirements, high consequence areas covered by this rule are populated areas, commercially navigable waterways, and areas unusually sensitive to environmental damage. (Section D provides more detailed definition and description of high consequence areas.) The final rule establishes new requirements to enhance and validate the integrity of hazardous liquid pipelines in high consequence areas. Furthermore, the rule prov des additional assurance that appropriate preventive and mitigative measures are in place to prote :t these high consequence areas. The final rule requires operators to develop and implement an Integrity Management Program for all portions of their pipelines that could affect high consequence areas. This Integrity Management Program includes at a minimum: a the identification of all pipeline segments that could impact high consequence areas, a a Baseline Assessment Plan to assure integrity of these segments, and a a framework that identifies how each element of the Integrity Management Program will be implemented. The operator’s Integrity Management Program must include the following elements: a a process for determining which pipeline segments could affect a high consequence ai-ea; a a Baseline Assessment Plan (as described below); a a process for conducting periodic integrity assessments and evaluation on those segments that could affect a high consequence area; a an analytical process that integrates all available information about pipeline integrity and the consequences of a failure (also noted above); a repair criteria to address issues identified by the integrity assessment method and dat i analysis; ’ Throughout the remainder of this Environmental Assessment, wherever “operator” is used in the text, it means hazardous liquid operators operating less than 500 miles of pipelin e used in transportation. 10#

Page 140 a process to identify and evaluate additional preventive and mitigative measures to protect high consequence areas; 0 methods to measure the Integrity Management Program’s effectiveness; and a process for review of integrity assessment results and data analysis by an individual qualified to perform evaluate integrity assessment results. Each of these elements must be addressed in the framework. Operators must follow recognized industry practices in their Integrity Management Program. The pipeline segments that could affect a high consequence area must be identified within nir e months of the rule’s effective date. The Baseline Assessment Plan and Framework must be documented within one year of the rule’s effective date. The Baseline Assessment Plan delineates the integrity assessment method(s) selected for eacli high consequence area, the schedule by which these initial integrity assessments will be performed, and the technical basis for integrity assessment method(s) selection and risk facto ’s used in scheduling the assessments. The rule requires operators to perform a baseline integril y assessment within seven years after the effective date of the rule for all pipelines that could a ‘fect a high consequence area, with 50% of this pipeline mileage being assessed within three and c ne- half years. In scheduling the baseline assessments, operators are to perform assessments of tlie highest risk segments first. Operators who have performed and documented integrity assessments in the five years previous to the effective date of the final rule may use these assessments to validate a pipeline segment’s integrity if the assessment approach and documentation are consistent with the provisions of the rule. The acceptable methods for conducting the baseline integrity assessment are pressure testing, instrumented internal inspection2, or other technology that the operator demonstrates can provide an equivalent understanding of the pipe’s condition. In evaluating the results of integrity assessments, operators must integrate information from ()her relevant sources with the inspection or testing results to hlly identify and characterize the potential threats to pipeline integrity. These other information sources might include cathodi c protection system data, close interval surveys, results of previous internal inspections, operat mg and leak history, patrolling reports, exposed pipe reports, etc. From this evaluation, the operator should identify the location, nature, and relative severity of anomalies and defects that could threaten pipeline integrity. Operators will be expected to address the important threats by evaluating and repairing, if necessary, defects or anomalies in the pipe. Operators must use ; L risk-based approach in prioritizing repair activities, in which any severe defects or damage that have the potential to result in a near term leak or failure are addressed immediately. The ruli : The integrity assessment methods used for low frequency, electric resistance weldel 1 (ERW) pipe and lap welded pipe susceptible to longitudinal seam failures must be capable o f assessing seam integrity and detecting corrosion and deformation anomalies. 11#

Page 15provides minimum mitigation and repair schedules and criteria that must be applied for certaii i, higher risk features identified through internal inspection. In addition to the initial, baseline integrity assessment, the rule requires that operators periodically reconfirm pipeline integrity in high consequence areas through regular integrity assessments. An operator must perform subsequent assessments of line segments that could affect high consequence areas no later than five years after the previous assessment.3 Within 1 his five year limit, operators must establish assessment frequencies commensurate with the risk e ich pipeline segment presents to a high consequence area. In other words, those segments present ng a greater risk to high consequence areas would be assessed more frequently than segments presenting lower risk. The risk factors to be considered when selecting integrity assessment methods and establishing a schedule for a particular segment include: m results of previous pressure testing and internal inspection data and results, a pipe design, materials, and manufacturing information, pipe coating type and condition, a leak history, and repair history, a cathodic protection system performance, m product transported, operating stress level, a a local environmental factors that could affect integrity (e.g., soil corrosivity, ground movement potential, and climatic factors), current or projected activities in the pipeline vicinity, and physical support of the segment such as by a cable suspension bridge. Guidance for identifylng and applying risk factors is provided in Appendix C of the final rulc The rule allows operators to extend the period between integrity assessments to more than five years if a reliable engineering evaluation and other external monitoring activities show the pipe to be in good condition, or if an integrity assessment technology the operator plans t I use is not readily available. If the justification for extending the re-assessment period is on an engineering basis, an operator must notify OPS nine months before the end of the five-year interval. If the justification is because of unavailable technology, an operator must notify OE'S 180 days before the end of the five year interval. 12#

Page 16Besides the integrity assessment provisions of the rule, operators also have to conduct an integrated evaluation of line segments that could affect high consequence areas to understand the greatest risks to these locations. This evaluation must include the results of the integrity assessments along with other information necessary to obtain a complete understanding of thc risk contributors to a particular pipe segment. As part of this evaluation, the operator must critically evaluate the effectiveness of existing preventive and mitigative risk control measure s, and consider if additional preventive and mitigative actions can improve protection for these areas. The operator must explicitly consider whether the installation of EFRDs or enhancing 1 eak detection system capability is warranted. The need for additional preventive and mitigative measures in high consequence areas must be periodically re-assessed in light of new informal ion such as changes in the pipeline condition, operating parameters, or the nearby population demity or environment. The final regulatory language articulating these requirements is provided in 195.450, 195.452, and the Federal Register Notice establishing the final requirements for operators who operate less than 500 miles of hazardous liquid pipeline. 13#

Page 17C. Alternatives Considered RSPA considered several alternatives in the decision process that led to the final rule. These altematives are summarized below. 1. Take No Action. In this alternative, RSPA would rely on the existing regulatory requiremc :nts to provide protection for high consequence areas. Without the provisions of the rule, operatoi’s would not be required to conduct the baseline integrity assessments, perform an integrated approach to integrity evaluation, conduct periodic reassessments, and consider other preventi Ive and mitigative actions for pipeline segments that could affect high consequence areas. By selecting this alternative, RSPA would not be responsive to the Congressional mandates to consider internal inspection and other protective measures for high population areas and area,; unusually sensitive to environmental damage (see Section A.2). 2. Require Mandatorv Intemitv Assessments in All High Consequence Areas Everv Ten Yea E. In determining the practical and appropriate requirements for operators who operate less thar 500 miles of hazardous liquid pipeline, RSPA considered establishing different requirements for conducting the baseline and subsequent integrity assessments than those established for oper, itors operating 500 or more miles of pipeline. Initially RSPA considered allowing up to ten years for this group of operators to conduct the baseline assessments on segments that could affect higli consequence areas, and allowing an interval for periodic reassessments of up to ten years. BI )th of these periods are longer than seven years allowed for baseline assessments, and the maxini um five year interval for subsequent assessments that were recently established for operators operating 500 or more miles of pipeline (65 FR 75378). RSPA was initially concerned that operators who operate less than 500 miles of pipeline would not have the financial and tech ical resources available to comply with the requirements described in Section B. RSPA was also concerned that during the initial few years, the demand for internal inspection tools might be more than the inspection device vendors could satisfy (with the simultaneously high demand being placed by operators operating 500 or more miles of pipeline). If internal inspection de vices were not available, operators would be forced to conduct hydrostatic testing to achieve compliance - which in some instances might not be the most desirable approach. During the period leading up to the proposed rule, RSPA reviewed its internal data, talked N ith several operators, and gathered information from its Regional inspectors who routinely inspcict these operators in standard compliance inspections. This investigation showed that many operators who operate less than 500 miles of pipe already perfom periodic internal inspection or pressure testing on sizeable portions of their pipeline system (see Section E. 1.3). Thus, RSF A’s initial assumption about the technical and financial resource capabilities of this group of operators was not valid. Furthermore, new information obtained from vendors of intemal inspection devices indicated that while the demand for these tools will be high, the industry should be capable of satisfying pipeline operators’ needs for shorter assessment intervals (see Section B). 14#

Page 18Finally, RSPA’s investigation revealed that a number of the facilities operated by operators m ith less than 500 miles of pipeline are located near populated areas. Imposing less stringent assessment requirements on these operators would be providing less assurance of pipeline integrity to the public in the vicinity of these facilities than for the public in the vicinity of facilities operated by operators with 500 or more miles of pipeline. Based on RSPA’s curren, understanding of industry capabilities and resources, there is no justification to establish requirements which would provide different levels of protection for different populated areas. Thus, RSPA concluded that there was no valid reason to impose different integrity assessmer It requirements on operators operating less than 500 miles of pipeline, from those established fc )r operators who operate systems with more miles of pipeline. 15#

Page 19D. Affected Environment The purpose of the integrity management rule is to provide additional protection to high consequence areas in the vicinity of hazardous liquid pipelines throughout the United States. The baseline integrity assessment and periodic re-assessments, as well as the additional preventiw and mitigative activities that evolve from the operator’s integrity management program, appljl to the high consequence areas along the operator’s system. Thus the primary areas of the environment impacted by this rule are high consequence areas defined as follows: e A high population area, which means an urbanized area, as defined and delineated by the U.S. Census Bureau, that contains 50,000 or more people and has a population densic! of at least 1,000 people per square mile. 0 An other populated area, which means a place, as defined and delineated by the Census Bureau, that contains a concentrated population, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial area. e A commercially navigable waterway, which means a waterway where a substantial likelihood of commercial navigation exists. These waterways are identified in the National Waterways Network, a geographic database created by the National Watenwys GIS Design Committee. It is available from the DOT Bureau of Transportation Stati:,tics at http://wuw. bts.gov/gi s/ntat 1 adnetworks. html. 0 An area of the environment that has been designated as unusually sensitive to oil spi‘ls (USAs). After completing a multi-year investigation with many agencies, industry, and other organizations, RSPA has published a final definition of USAs (65 FR 80530, December 21,2000). The USA definition includes drinking water and ecological resource areas. For drinking water resources, USAs would include: t The water intake for a Community Water System (CWS) or a Non-transient Non- community Water System (NTNCWS) that obtains its water supply primarily fi-om a surface water source and does not have an adequate altemative drinkir g water source, t The Source Water Protection Area for a CWS or a NTNCWS that obtains its water supply from a Class I or Class IIA aquifer and does not have an adequa1.e alternative drinking water source. Where a state has not yet identified the SVYPA, the S W A is replaced with the Wellhead Protection Area. t The sole source aquifer recharge area where the sole source aquifer is a karst aquifer in nature. For ecological resources: 16#

Page 20t An area containing a critically imperiled specie or ecological community, t A multi-species assemblage area, t A migratory waterbird concentration area, t An area containing an imperiled, threatened or endangered, or depleted marinc mammal species that is aquatic, aquatic dependent, or terrestrial with a limited range, b An area containing an imperiled ecological community that is aquatic or aquatic dependent , An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or imperiled ecological community that is considered to be the most viable, highest quality, or in the best condition, as identified by an element occurrence ranking of A (excellent quality) or B (good quality). 49 CFR 195.6 provides a comprehensive list of definitions and terminology necessary to fully identify these USAs. RSPA intends to prepare maps delineating the specific high consequence areas across the United States. The specific geographic locations of the high population areas, other populated areas, commercially navigable waters, and USAs will be mapped using the National Pipeline Mapping System. Operators and the public will have access to these maps through the Intemet. Oper:i.tors will then be able to determine locations where a spill from their system(s) could affect a higl- consequence area. After they are initially established, high consequence areas will be updated on a periodic bas s to incorporate new information and data. For example, as communities grow, the boundaries o f high population areas may shift, thus the operator will need to assure protection consistent with the provisions of the rule in these new locations. Similarly, the identification of USA locaticins will be updated reflecting changes in species listings and their locations, and changes in the availability of drinking water resources. RSPA is currently considering the review and updale of high consequence area data and maps every five years. In addition to the high consequence areas, the provisions of the rule will also impact areas oj 'the environment outside of high consequence areas. For example, it is expected that many operiitors will elect to use internal inspection devices to perform the baseline and periodic integrity assessments. Due to economic and operational considerations, the launchers and receivers u sed to insert and remove internal inspection devices are typically located at pump stations, whicl I can be many miles apart. Even though a high consequence area may exist for only a short distani :e along the line, because of the location of pig launchers and receivers, operators will likely inspect 17#

Page 21the entire pump station-to-pump station segment of a line. Thus, in addition to the informatic n about the condition of the line in a high consequence area, the operator should obtain integripr data about a much larger segment of pipe. Any significant threats identified in these addition i1 areas will also be remediated, thus providing additional protection for the regions adjacent to high consequence areas. 18#

Page 22E. Environmental Consequences of Proposed Action and Alternatives This section describes the expected impact to the environment of the final rule (Section E. 1) ; tnd the altematives (Section E.2). E. 1 Environmental Impact of the Integitv Management Rule Section B describes the complete set of requirements for the rule. The essential features of tf.e new requirements are summarized below. 0 Operators must pressure test or internally inspect4 a11 lines segments where a spill cou Id affect a high consequence area within seven years of the date the rule becomes effective. Assessments conducted within five years prior to the rule effective date may also be accepted as demonstrating adequate integrity of a line segment. Operators must prom )tly remediate any defects discovered through these assessments that might threaten pipe1 ne integrity. 8 Operators must periodically evaluate the integrity of its pipeline using a process that integrates information from other relevant sources with inspection or testing results to fully identify and characterize the potential threats to pipeline integrity. As a result o this integrity evaluation, line segments that could affect a high consequence area must als be periodically re-assessed no less than once every 5 years. (Limited exceptions may be permissible subject to RSPA review.) * As part of the integrity evaluation, operators must identify and evaluate the need for additional preventive and mitigative actions to protect these areas, including EFRDs .ind enhanced leak detection capability. The need for additional preventive and mitigative measures would be periodically re-assessed. Performance measures must be used to characterize the effectiveness of the risk control activities and integrity program provisions, and to make any modifications to assure continued protection for high consequence areas. The impacts of each of these proposed requirements are discussed in this Environmental Assessment. This information is organized as follows: 8 A brief summary of internal inspection and pressure testing is provided in Section E. I. 1. 0 The environmental impacts of these integrity assessment methods are then described in Section E. 1.2. 4 The rule also allows for other technologies, but for purposes of this EA, it is assum:d that all operators will either pressure test or pig to meet this requirement. 19#

Page 23The environmental impacts of the baseline internal inspection and pressure testing provision of the rule are described in Section E.1.3. In this section, the current industiy internal inspection and pressure testing practices are compared with what will be requ ired when the rule takes effect. e The environmental impacts of the periodic assessment requirement are discussed in Section E. 1.4. Finally, the environmental impacts of the other preventive and mitigative measures a e considered in Section E. 1.5. E. 1.1 Overview of Internal Inspection and Pressure Testing Internal in-line inspection, also referred to as “smart pigging,” involves the use of an electronically instrumented device traveling inside the pipe that measures characteristics of tl Le pipe wall. There are several different technologies used by intemal inspection devices. The most common tools in use are: Geometry pigs, which contain electronic sensors that detect geometric or configuratictn changes in the pipe such as dents, buckles, wrinkles, and ovalities. They are used to identify construction-related or other outside force damage. 0 Magnetic flux leakage pigs, which produce a magnetic flux field in the pipe wall and through the measurement of flux leakage identify changes in wall thickness. Flux variations are used to indicate Iocalized pipe wall thinning due to internal or external corrosion, or certain types of gouges. Recently developed tools with a circumferentially oriented magnetic fields have successfully identified axial seam corrosion and some txial cracks. Ultrasonic tools, which use sound waves to identify anomalies. There are several de:,,igns of ultrasonic tools capable of detecting wall thinning and crack or crack-like defects. The capabilities of intemal inspection devices are improving continuously. New technology and innovation are increasing the accuracy with which defects can be detected, developing high quality inspection capability for smaller diameter pipelines, and developing new or improve1 1 techniques to detect a broader range of defects, such as stress corrosion cracking defects and hook cracks in pipe seams. Currently, there is no single intemal inspection tool that can detect all types of pipeline defects or damage. Hence, the selection of a specific tool depends on whal type of anomalies or defects the operator is trying to identify. Some operators run geometry or caliper pigs, in combination with magnetic flux leakage tools in order to identify both geometric defects, as well as corrosion metal loss. A more complete description of these tools, as well as other in- line inspection technologies, can be found in the literature, including several of the referencc :s cited in Section J. 20#

Page 24The internal inspection tool output is analyzed to identify the location and severity of pipe wa 1 anomalies or defects. Several industry-accepted methods are used to determine the severity o . flaws and the remaining strength of the pipe. These include ASME B3 1 G, ASME B3 1 G Modified, and RSTRENG. In addition, pig vendors, consultants, and operators are developin< ; more sophisticated analytical tools to take advantage of the increasing quality and accuracy of the data available from higher resolution inspection tools. These calculations consider the depth, geometry, and configuration of corroded areas, as well as the proximity to other anomalies to estimate the remaining strength of the pipe at the location of the anomaly. The calculations a e used to identify which anomalies are in need of repair (i.e., those areas where the remaining pilpe strength is approaching a level where integrity during future operation might be compromised), and to prioritize the excavation and examination of pipe wall defects. After interpreting and analyzing the results from a pig run, operators typically develop an excavation and repair plan. This plan involves excavating selected anomaly locations to examine the extent of damage and thus confirm the information identified by the pig. After validating the accuracy of the pig runs through these confirmation digs5, the operator will excavate, examin.:, and repair, if necessary, those anomalies that have the most potential to threaten pipeline integrity. Operators develop their own criteria for scheduling anomaly repair work. Typically those indications that might pose a near t e m or immediate threat to pipeline integrity are repaired as soon as possible. Other, less severe indications typicaliy become part of a longer term maintenance plan. In addition to preventing leaks and accidents, internal inspection provides many operational benefits as well. The inspection results can be used to customize long term maintenance plans, rather than using a “one-size- fits-all” maintenance approach. Internal inspection can also he1 p verify the effectiveness of a pipeline maintenance program. Finally, internal inspection results can be used to fine-tune system operational parameters. For these reasons, as well as the safi:ty benefits, hazardous liquid operators are increasingly relying on internal inspection as a key element of their operation, maintenance, and integrity management programs. The other method of direct integrity assessment is hydrostatic pressure testing. During a hydrostatic test, a segment of the pipeline is filled with water, pressurized to a predeterminetl pressure, and held at this test pressure for a predetermined length of time. This testing is performed to eliminate any significant material defects or flaws that might result in failure. 1 ‘he test pressure normally exceeds the maximum allowable operating pressure (typically by 2%). Thus the pipe is subjected to stresses much higher than it would encounter during system operation. After the testing is completed, the only defects remaining in the pipe are those th it should not fail at the lower, normal operating pressures. Hydrostatic testing is especially Val iable in ensuring that significant longitudinal seam weld flaws and stress corrosion cracks are not present. These types of defects can be difficult to detect with many types of internal inspection devices. Some operators that use modern, high resolution magnetic flux tools do not perform confirmation digs. 21#

Page 25E. 1.2. Environmental Impacts of Internal Inspection and Pressure Testing As described in the previous discussion, the purpose of internal inspection and hydrostatic pressure testing is to identify and repair defects or anomalies in the pipe wall that might result in failure if operation were to continue with these defects still in place. Defects such as serious corrosion damage, deformation incurred during construction, and outside force damage to the! pipe can be identified by these inspection techniques and repaired. Eliminating or repairing these defects provides greater assurance of pipeline integrity, and reduces the probability that the pipe will fail during subsequent operation. Thus the environmental consequences of a hazardous liquid spill are avoided. The specific environmental impacts of a release depend on the environmental features in the immediate proximity to the failure location. Impacts also depend on numerous factors includ ng the pipe size and operational parameters, failure size, product released, control center’s actio] is taken in response to the leak, and effectiveness of emergency response efforts. Pipelines trav erse a broad spectrum of environments, and the impacts of a release can vary considerably. Experience has shown that pipeline spill consequences can vary from minor, local soil contamination to major, long term damage to environmental resources. Adverse impacts to human health and safety can also occur. Appendix 1 provides a general description of the environmental impacts of hazardous liquid spills. While internal inspection and pressure testing and repair can not eliminate all pipeline failurc s, they can reduce the frequency of these events. Thus on a national scale, the cumulative environmental damage from pipeline spills is reduced. Since the provisions of the rule will bc implemented on line segments that can affect populated areas, USAs, and commercially navigable waters, it is expected that these resources will benefit by the reduced likelihood of pipeline failure in these areas. Even though these integrity assessment and repair practices can reduce the frequency of spills to the environment, they are not without some adverse impacts. These are summarized below. Although hydrostatic testing is an important tool to identify potentially critical defects, the process does have some minor adverse environmental impacts. RSPA considered these imp2 cts in preparing an Environmental Assessment for the rulemaking on “Risk-Based Alternative to Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines” (63 FR 59475, Docket # PS- 144). The key points from this Environmental Assessment are summarized below. Ma re detailed information is available in the Environmental Assessment posted to the docket. Generally there is some disturbance of the pipeline right-of-way, as short segments of the lini : may have to be uncovered to conduct the hydrostatic test. However, there is no significant iu pact on the surrounding land or vegetation as a result of site preparation for the test. There shoulc be very little or no other types of environmental impacts such as noise, air, water, or soil pollutic m because of the limited amount of equipment (typically a backhoe and pumps) needed on site md their operating characteristics. 22#

Page 26The water used for hydrostatic testing mixes with the residue of the hazardous liquid that rem2 ins in the pipeline. As a result, the test water becomes a hazardous material which, after the testing is completed, must be disposed of in a manner governed by EPA regulations. (National Pollut ant Discharge Elimination System Permits are required.) Accidental discharges of test water resulting from a line failure or spill during a hydrostatic test will result in a release of water with the accompanying oil or product residue to the environmc nt immediately adjacent to the release point. The low levels of oil residue in the test water should have a minimal impact on the surrounding environment. The test is also closely monitored by operator personnel at the scene who are prepared to respond rapidly and effectively to any leaks or spills during the testing process. Industry experience with numerous hydrostatic tests has shown spills of test water to be infrequent, generally of small volume, and result in no signific ant or lasting environmental effects. Similarly, internal inspection has some minor adverse environmental impacts. If the pipeline is not already equipped to conduct an internal in-line inspection, the operator must install launcliers and receivers to insert and remove, respectively, the internal inspection device. In some situations, valves or other appurtenances may need to be replaced or modified to allow these devices to pass through the line. Typically launchers and receivers are installed at pump statit Ins, and no additional environmental disturbance is required. In other instances where new launcl iers and receivers must be installed along the pipeline route, and when mainline valves need to be modified or replaced to accommodate inspection devices, there may be a localized disturbance of the area along the pipeline right-of-way. This disturbance is only for a small localized area 0.1 the right-of-way, and does not involve additional vegetation or environmental disturbance beyond the equipment site. Furthermore, when the operator identifies anomalies that need to be examined and perhaps repaired, there is additional localized disturbance along the right-of-way where the excavatio '1 occurs. This localized disturbance is confined to the small region of the line where the anom.aly is located, and typically does not involve damage to vegetation or the environment beyond thlz immediate vicinity of the pipeline corridor. This localized ground disturbance to correct a dtifect, has far less impact than a leak or failure that might occur if the defect were to remain in the pipe and ultimately fail. Based on extensive industry experience, RSPA believes that the benefits of hydrostatic testir g or in-line internal inspection in reducing the likelihood of a significant oil spill offset the minor adverse impacts of these techniques described above. E. 1.3. Environmental Impacts of Baseline Integrity Assessment Requirements in Final Rule To understand the environmental impact of the rule, it is necessary to understand the intemal inspection and pressure testing programs currently in place, and compare them to the progra ns that will be required when the rule becomes effective. As discussed at the beginning of this Environmental Assessment, pipeline operators have strong incentives to ensure the integrity of 23#

Page 27their pipeline assets. As a result, many hazardous liquid pipeline operators have some integdy management activities in place. The use of internal inspection and hydrostatic testing to periodically confirm pipeline integrity are already common liquid pipeline industry practices. Most hazardous liquid pipeline operators strongly prefer intemal inspection to pressure testin!; as a means of assuring line integrity. Internal inspection provides a wealth of data about the pipi: condition that can support improved operation and maintenance, as well as assure pipe integrity. Hydrostatic testing provides essentially no data on the pipe condition other than, at the time c f the test, it is capable of withstanding a given pressure. Operators contacted during the preparation of this Environmental Assessment strongly agreed that given a choice between thse two approaches, pressure testing would only be employed where the system design precluded pigging, or where intemal inspection technology is not able to detect certain types of flaws. In developing an integrity management strategy for a given system, operators consider nume1 DUS factors including the pipeline’s design parameters and manufacturing process, coating type a~ id condition, age of the system, cathodic protection system performance, observations of pipe condition when the line is exposed for maintenance or other reasons, leak history, operational parameters, and the results of previous hydrostatic tests, intemal inspections, or close interval surveys. Many operators also consider the proximity of the line to population centers and environmentally sensitive resources, as well as their commitments to deliver products to thei customers, in developing testing and inspection plans. Because these factors are unique to e x h pipeline system as well as line segments within a system, each operator’s intemal inspection ;and pressure testing program is customized to address the specific needs of the pipeline systems i t operates. To understand the current integrity assessment activities of operators operating less than 500 miles of pipe, RSPA examined the intemal inspection and pressure testing activities of a nun tber of these operators. This was accomplished by reviewing internal data sources, interacting with selected operators, and discussing operator assessment practices with the OPS Region inspec tors who regularly inspect these operators. While there is a wide variation in the integrity management practices of these companies, most of these hazardous liquid pipeline operators appear to have a regular program of intemal inspection or pressure testing. From this limitecl sample of operators (covering -1 500 miles of regulated piping), roughly two/thirds of the line pipe had been intemally inspected or pressure tested in the last five y e a s 6 For these operatc rs, the baseline and periodic integrity assessment requirements in the new rule would have little While this data applies to entire operator pipeline systems, the initial assessment requirements in the rule apply only to portions of the line that could affect high consequence areas. Since the mapping of high consequence areas has not been completed at this time, it is difficult to estimate the current rate at which pipelines that could affect these areas are inspe :ted or tested. In considering the environmental protection currently afforded high consequence i ireas (without the provisions of the rule), it is assumed that the rate at which lines near high consequence areas are intemally inspected or pressure tested is comparable to the overall rat; at which operators voluntarily inspect or test their system. 24#

Page 28impact since they are already conducting integrity assessments at a frequency comparable to tliat required by the rule. However, there are also some operators who will not have performed internal inspection or pressure testing in the previous five years. In the sample of operators examined in this study, these operators’ systems comprised less than 10% of the total pipeline mileage. Based on thi,,; very limited sample, as well as OPS inspection experience, it is believed that operators who c o not have periodic internal inspection or pressure testing programs are believed to be primarill1 companies with very low pipeline mileage (i.e., tens of miles). To account for operators that have no integrity assessment activities, as well as for the portioi is of the other operators’ systems where integrity assessments may not have been performed, RSPA assumed that the rule will result in internal inspection or pressure testing of approximately 1(1% of the line segments that could affect high consequence areas that would not be otherwise assessed. As determined by the Regulatory Evaluation’, this means approximately 540 miles of pipe in high consequence areas will receive additional protection provided by the baseline an ,j periodic integrity assessment requirements of the rule, that would not otherwise have been subjected to integrity assessments. A simple scoping calculation was performed to estimate the potential benefits of internal inspection in these 540 miles. This calculation assumes that the nationwide incident statistic ,; for all hazardous liquid lines are applicable to high consequence areas. In order to estimate an u‘ )per bound on the environmental benefits that might occur from the initial baseline assessment requirement, it is assumed that internal inspection and defect repair will eliminate all failures caused by internal or external corrosion, and prior outside force damage. In fact, although serious corrosion and defects from previously damaged pipe will be detected and removed following the baseline inspection, it is not possible to preclude additional such failures beforf: subsequent integrity assessments occur. It is possible that corrosion processes may still be acmtive, and could result in failure prior to the next inspection. Similarly, third parties could damage the pipe after the repairs to previous outside force damage have been repaired. Thus, assuming t’hese failure modes are eliminated means that this scoping calculation overestimates the environm .:ntal benefits. This calculation estimates that over the initial seven years where operators must complete thl: baseline inspection in high consequence areas, there is approximately a 20% chance that a fa [lure from corrosion or previously damaged pipe might occur in the 540 miles of pipe that would receive additional protection afforded by this rule. If it is assumed that the internal inspection and repair eliminates these failure mechanisms, the rule would in effect prevent 0.2 incident!, in high consequence areas over the period where the baseline integrity assessments are perform ed. Applying the breakdown of high consequence area mileage used in the Regulatory Evaluation, ’ “Regulatory Evaluation: Pipeline Integrity Management in High Consequence Area:; (Hazardous Liquid Pipeline Operators with less than 500 miles of Pipelines),” Docket RSPF. 00- 7408, September, 2001. 25#

Page 29less than half of these incidents would occur in USAs or near commercially navigable waters; the remainder would occur in high or other populated areas. The net spill volume discharged to the environment for pipe failures caused by corrosion and previously damaged pipe is approximately 320 bbls per incident.8 Applying this number to th e above failure rate indicates that from a statistical perspective, some 64 bbls of net product losl. to the environment would be avoided through seven years of the baseline assessment and repair provisions of the rule. It is likely that not all of the 540 miles used in the above calculation will be intemally inspect,:d. The lack of launchers and receivers, and system design factors may preclude pigging. For thcise portions of pipeline systems that operators are expected to pressure test instead of conducting an intemal inspection, the impact will be positive, as well. Large defects that seriously compron iise the design margin in the pipe will be discovered, and repaired. However, the magnitude of benefits may be less than for intemal inspection. Although pressure testing will identify certain types of defects that intemal inspection may miss (e.g., large, integrity-threatening seam defel :ts), hydrostatic testing does not identify defects that “just survive” the test, but over time may 1ea.i to failure during operation (e.g., through cyclic fatigue crack growth associated with normal operational fluctuations). Internal inspection would detect many of these “near critical” defec :ts. Since some portion of the 540 miles addressed in the previous scoping calculation will be pressure tested rather than intemally inspected, the estimated 0.2 incidents avoided over the initial seven year period represents an upper bound on the number of incidents prevented. The initial integrity assessment required by the rule also provides an important baseline against which future evaluations of line integrity can be compared. Integrating the results of an initial internal inspection with cathodic protection data, close interval survey results, patrolling and one- call information, and other sources supports a more comprehensive evaluation of all factors that influence line integrity. It also provides a valuable benchmark against which hture intemal assessments can be compared to understand how conditions in the pipe are changing over time. While these benefits can not be quantified, they are important to providing a comprehensive ind long term assurance of system integrity in high consequence areas. In conclusion, it appears that the requirement to conduct the baseline internal inspections or pressure test all line segments that could affect high consequence areas will result in a very sinal reduction in the number of pipeline failures at these locations, and the impacts that would accompany these failures. In populated areas, preventing such failures would provide additio nal protection to the public in the vicinity of the pipeline. In the USAs and commercially navigz ble waters, the environmental damage to these resources following a pipeline failure will be avo ded. Because the segments tested or inspected will likely encompass portions of the pipeline beyc nd the boundaries of the high consequence areas, this additional protection will be provided to 2 greater length of pipe adjacent to the high consequence areas. However, because the total “Analysis of DOT Reportable Incidents for Hazardous Liquid Pipelines, 1986 Thro .igh 1996,” API Publication 1 158, January 1999. 26#

Page 30pipeline mileage that is in high consequence areas is expected to be small for operators opera ing less than 500 miles of pipe, the benefits in terms of number of incidents and amount of oil sp. lled are small. Finally, it should be recognized that the initial baseline integrity assessments will not prevent all pipeline failures in high consequence areas. In particular, third party damage from excavator:,;, one of the most significant contributors to pipeline failures, is not effectively addressed through internal inspection or testing. Although serious outside force deformation or metal loss that significantly damages, but does not fail, the pipe will likely be discovered, integrity assessment has no impact on failures where the excavation damage immediately fails the line. The requirement to evaluate high consequence area line segments for additional preventive acti0n.s is designed to address third party damage, as well as other risks not addressed through inspection and testing (see Section E.l S). E. 1.4. Environmental Impacts of Periodic Assessment Requirement in the Final Rule The rule also provides for periodic assessment of line segments that could affect high consequence areas. Reconfirming pipeline integrity in these areas is important as conditions change over time. While the initial, baseline assessment establishes the integrity at the time he test is conducted, it is possible that small defects remaining in the pipe may become larger dtiring subsequent operation. Thus over time, the confidence in the integrity of the line is diminished. For example, although hydrostatic testing will eliminate defects that could result in pipe faillire at normal operating pressure, it does not identify smaller cracks that are not large enough to fai under the test pressure. These smaller defects remain in the pipe and can be subject to enlargement when the pipeline is returned to service. For example, corrosion pits may become larger if there is ineffective cathodic protection; or pressure fluctuations during operation may cause existing small cracks to grow due to cyclic fatigue. These defects may grow to a critic;nl size that over time could result in pipe failure. Fortunately, under normal operating conditio i1S with good corrosion control programs, growth rates for defects remaining in the pipe after a pressure test are generally very slow. The same situation exists for pipeline sections that have been smart pigged. Modern internal inspection tools, especially high resolution tools, will often identify a large number of featur.:s in the pipe wall. The vast majority of these are very small indications that will not threaten pip dine integrity. Because these minor features pose negligible risk, it is not practical or economical to excavate and repair all of these indications. However, if the corrosion control is ineffective in a localized area, some of these smaller anomalies might continue to grow under continued operation. An on-going, integrated evaluation of line integrity, including periodic testing, is desirable to assure the pipeline condition is not significantly degrading, as well as to identifil new problems that might occur during operation subsequent to the baseline assessment (e.g., undetected third party damage that dents the pipe, but does not cause immediate failure). 27#

Page 31The rule requires operators to re-assess line segments in high consequence areas no less frequently than once every five years with limited exceptions. Furthermore, operators are to consider a number of risk factors to ascertain if more frequent assessments are needed. Operzitors will be allowed to use longer assessment intervals provided they can justify this decision by a reliable engineering evaluation in conjunction with other monitoring technologies that provid.: a high confidence that the pipe is in good condition. Most operators with internal inspection and pressure testing programs recognize the need to conduct these assessments periodically to provide continued assurance of integrity. There arc several different philosophies on when and how to conduct periodic integrity assessments. Furthermore, operator approaches on periodic assessment are evolving. This is driven in pari by the advances in internal inspection tool technology, and improved analytical methods, that provide better information upon which to base future inspection decisions. Some operators initially established a set integrity assessment periodicity (e.g., every 10 years for all lines). However, as advances in inspection technology provide more information about their system condition, and operators integrate information from other sources, such as cathodic protectioi I readings, exposed pipe reports, and close interval surveys, they are establishing integrity assessment frequencies that are customized for the unique conditions and characteristics of particular line segments. Some operators now have formal integrity management programs tk at provide a technical basis for making these decisions. The integrity management program requirements in the rule will assure that all operators have such programs, and thus more a more technically defensible basis for making periodic assessment decisions, as well as other risk control activities (see Section E.1.5). After considering the previously discussed operator assessment practices information, and examining internal inspection and pressure testing programs of several liquid pipeline operat ,xs, RSPA believes that the periodic inspection and testing requirements for high consequence ar.:as in the rule will result in a greater frequency of testing or intemal inspection for a larger number of high consequence areas than would have occurred without the provisions of the rule. Infoimal discussions with operators indicate that the majority of operators with intemal inspection programs have test frequencies of ten years or less - especially in areas that they know would have serious consequences should a failure occur. However, relatively few operators perforr 1 integrity assessments on a five year cycle in all areas of high population or environmental sensitivity. The relative benefits of a five year assessment cycle versus the longer periods used currently by many operators is difficult to estimate. If the operator identifies and repairs all significant anomalies following the baseline assessment, and then assures that strong risk controls are iIi place to prevent corrosion and other integrity threats (as required by the rule), it is likely that integrity assessments every five years will be only marginally more effective in reducing incidents due to corrosion and unrecognized outside force damage than conducting integrity assessments every ten years (a period that is more representative of current operator practice,;). 28#

Page 32Some operators covered by the rule have formal, established integrity management programs. These operators may elect to use risk analysis and/or engineering evaluations such as cycle fatigue crack growth models to justify a periodic assessment interval longer than five years or segments that the baseline assessment shows to be in good condition, and where strong risk controls are in place to minimize the occurrence of a leak or spill. In these cases, the impact crf the rule on an operator’s periodic integrity assessment program would likely be small. Periodic testing and inspection will assure that the higher level of confidence in the line integ ity that was achieved from the initial baseline test is maintained. Thus it is expected that the imr act on the likelihood of failures fiom corrosion and previously damaged pipe would be similar to, or somewhat less’ than, the estimates provided in the previous section. Hence, the periodic assessment requirements of the rule will have a small positive benefit in terms of environmen tal protection when compared to existing operator practices for periodic integrity assessments. E. 1.5. Environmental Impacts of Other Preventive and Mitigative Actions The final major element of the rule is the requirement that operators periodically review the existing preventive and mitigative measures in place for each high consequence area, and consider what additional activities or enhancements to these measures might be warranted to enhance protection. In conducting this evaluation, operators will be expected to examine the entire range of threats to pipeline integrity in high consequence areas, integrating information from all applicable and available sources, including applicable experience along the entire pipeline. RSPA expects operators to consider (at a minimum) information such as: e Pipeline design features, including wall thickness, type of seam and pipeline age; e Construction practices and information; e Operating history, including leaks and incidents; e Maintenance and surveillance records, including cathodic protection system perform2 nce, and patrolling; e Previous inspectiodtesting results (internal inspection, pressure testing, or close inte1 Val surveys) and time since last inspection; e Exposed pipe reports, including coating condition; e Condition of above-ground equipment; One the baseline assessment has been performed, significant construction related defects, and outside force and corrosion defects that may have existed for many years will bc removed. Assuming a sound program of risk controls is in place, subsequent inspections wi 1 generally discover fewer significant anomalies. 29#

Page 33a Susceptibility to natural hazards such as ground movement; a Damage prevention program effectiveness; a System operating parameters and SCADA system performance; a Commodity transported; 0 Proximity to and specific features of the high consequence area (e.g., population dens ty distribution, type of environmental resource); a Mitigation feature effectiveness in limiting the volume of product released; and a Spill response plan effectiveness and availability of equipment. The integrated evaluation of this information should identify location-specific conditions tha1 might pose significant risks in high consequence areas, and support improved decisions to prl Itect these areas. Operators will be expected to identify the major risks in high consequence areas, prioritize these risks, and consider what actions might be warranted to address the most important risks. As part of this evaluation, RSPA expects operators to critically evaluate the effectiveness of their existing prevention and mitigation measures as part of this process. Tht rule also requires that operators explicitly consider whether EFRDs or enhancements in leak detection capability are needed to protect high consequence areas. Operators will also be required to evaluate the effectiveness of their integrity management program through performance measurement. This periodic evaluation will assure that the program is continually effective in managing and reducing risk in high consequence areas. 01's review of inspection results, integrity analysis, and consideration of additional preventive anc I mitigative actions will provide added assurance that a thorough evaluation has been conductcsd and operators have implemented an appropriately strong program to protect high consequencl? areas. As a result of this evaluation, some operators may elect to implement additional risk control activities to enhance protection for high consequence areas. For example, depending on the ,de- specific situation, operators may decide to: a Implement some of the damage prevention best practices identified in the recent Conimon Ground Report in an area where population expansion and increased construction is expected; a Implement new technologies capable of providing full time monitoring o f cathodic protection levels at locations where corrosion is a high concern; 30#

Page 34Install an additional block valve that would minimize the amount of product released i n the event of a spill; Install remote operators on block valves so that the line could be isolated more rapidlj after a significant failure occurs; Install check valves to prevent flow reversal in the event of a break, thus minimizing the amount of product released to the environrhent; Upgrade SCADA and leak detection system capabilities; Pre-stage emergency response equipment so that in the event of a spill, effective respc nse actions can be mobilized more quickly; or Conduct drills with local emergency responders that are focused on protection of a specific high consequence area. Additional preventive or mitigative actions such as these will evolve fiom the operator’s ana1:ysis of the risks in specific high consequence areas. As such, they will be operator and site specif c. The existing pipeline safety regulations already protect high consequence areas. The new integrity management rule provides additional protection because of the sensitivity of these a .eas to pipeline failures. Some operators recognize the importance of preventing accidents in these areas, and have programs and activities that extend beyond the regulations to provide additioi la1 protection. For this reason, it is expected that some operators may determine that a number cf their high consequence areas already have adequate protection, and that further actions woulcl not produce the demonstrable benefits. Without knowing where the high consequence areas are located, and without operators havin:g performed the risk analysis noted above, it is not possible to make definitive conclusions on 1 he impact of this provision of the rule. Based on discussions with selected operators, RSPA believes that this provision may result in additional risk control measures for a small number of high consequence areas, and thus improved environmental protection at these locations. This is rnost likely to occur in a high consequence area that the operator had not previously identified. W iile these additional preventive and mitigative measures will provide enhanced protection for the specific locations, in aggregate they are not likely to be significant on a nationwide scale. E. 1.6 Summaiy of Environmental Impacts for Final Rule As a whole, the combined impacts of the initial baseline integrity assessment (pressure testin g or internal inspection), subsequent periodic assessments, the integrated and continuous evaluation of line integrity, additional preventive and mitigative measures that may be implemented in 1 iigh consequence areas, and performance measurement of the integrity management program wil result in positive environmental impacts. The number of incidents and the environmental 31#

Page 35damage from failures in high consequence areas should be reduced slightly. From a national perspective, the impact is not expected to be significant for the pipeline operators who operatc:: less than 500 miles of pipeline for the following reasons: Many operators covered by the rule already have intemal inspection and pressure testi lg programs that cover most, if not all, of their pipeline systems. These operators typically place a high priority on the pipeline’s proximity to populated areas, commercially navigable waterways, and environmental resources when making decisions about whei-e and when to inspect and test pipelines. As a result, some high consequence areas havc : already been recently assessed, and a large fraction of remaining locations would probably have been assessed in the next several years without the provisions of the rule. The most tangible impact of the rule will be to ensure assessments are performed for those line segments that could affect a high consequence areas that are not currently b zing internally inspected or pressure tested, and ensuring that integrity is maintained throuilh an integrity management program that requires periodic assessments in these location! I . Because pipeline failure rates are low, and because the total pipeline mileage operated by operators with less than 500 miles of pipe that could affect high consequence areas is small (estimated to be -5440 miles), the rule has only a small effect on the likelihood of pipeline failure in these locations. Using recent hazardous liquid pipeline failure data, the number of failures avoided by the baseline assessment provision of the rule is estimat :d to be less than one, nationwide. The rule will result in more frequent integrity assessments of line segments that could affect high consequence areas than most operators are currently conducting (due to th : five year interval for periodic assessment). However, if the operator identifies and relrairs significant problems discovered during the baseline inspection, and has in place solid risk controls to prevent corrosion and other threats (as required by the rule), the benefits o 1’ testing every five years versus the longer intervals operators more typically employ arlz not expected to be significant. The rule requires operators to conduct an integrated assessment of all potential threat:; to pipeline integrity, and to consider additional preventive or mitigative risk control measures to provide enhanced protection. If there is a vulnerability to a particular fai lure cause - like third party damage - these evaluations should identify additional risk coni rols to address these threats. Some of liquid operators covered by the rule already perform integrity evaluations or formal risk assessments that consider the environmental sensitivity and impacts on population. These evaluations have already led to additior a1 risk controls beyond existing requirements to improve protection for these locations. Without identifying the specific high consequence area locations, the specific risks present at these locations, and the existing operator risk controls (including those thal surpass the current minimum regulatory requirements), it is difficult to determine the impact of this requirement for additional preventive and mitigative activities. Howel er, for many companies, it is expected that additional risk controls will be limited and customized to site-specific conditions that the operator may not have previously 32#

Page 36recognized. For many high consequence areas, it is probable that operators will determ. ne the existing preventive and mitigative activities provide adequate protection, and that tl le small additional risk reduction benefits of additional activities does not justify their implementation. Finally, an important, although less tangible, benefit of the rule will be to establish requirements for operator integrity management programs that assure a more comprehensive and integrated evaluation of pipeline system integrity in high conseque ice areas. In effect, this will codify and bring an appropriate level of uniformity to the integrity management programs some operators are currently implementing. It will also require operators who have limited, or no, integrity management programs to raise thej r level of performance. This rule will impose the same integrity management requiremei its on operators operating less than 500 miles of pipeline as those recently issued for operators operating 500 or more miles of pipe (65 FR 75378). Thus, the rule is expeckd to provide a more consistent, and overall, a higher level of protection for high consequence areas across the industry. While this impact is certainly positive, it is no1 possible to quanti@ in terms of improved safety and environmental protection. E.2. Environmental Impacts of the Alternatives E.2.1 Take No Action. Under the “No action” alternative, RSPA would not issue any rule requiring assessment or integrity management for hazardous liquid pipelines in high consequence areas. It is expected that existing pipeline operator integrity management activities (both those required by Part 1 S 5 , and those the operators perfonn voluntarily), as well as OPS oversight, would continue. After RSPA identifies unusually sensitive areas (as described in 65 FR 80530, December 21, 2000), and depicts them on maps with commercially navigable waters and populated areas, it is expected that some operators may voluntarily examine portions of their pipelines that are in cIr near these areas, and review their existing preventive and mitigative risk control measures fo:,, these locations. Some operators may voluntarily perform integrity assessments or implemenl additional risk control activities. However, as noted previously, most operators are aware of the environmentally sensitive areas and populated regions along their pipeline systems, and have taken what they believe to be appropriate actions to prevent and respond to spills at these locations. Thus it is expected that most additional, voluntary actions taken to protect high consequence areas would probably be limited to a small number of specific locations - prima,dy where mapping identifies a high consequence area that the operator had previously not recognized. In summary, the “no action’’ alternative would have essentially no impact on environment. 1 ‘he benefits from increased integrity testing and inspection, more formal and integrated approaches 33#

Page 37to integrity management, and OPS oversight of operator integrity management plans for high consequence areas that are key elements of the rule would not be realized under this altemativ:. E. 2.2 Mandatory Integrity Assessment in all High Consequence Areas Every Ten Years This altemative requires that the initial baseline assessment of pipeline segments that could affect high consequence areas be completed in a longer period than the rule (i.e., ten years instead oi' seven years). This altemative also provides a longer maximum interval between subsequent integrity assessments - up to ten years between assessments versus the five year limit in the filial rule. After conducting an integrity assessment, an operator has a high degree of confidence that the pipeline segment has no significant defects which might result in near-term failure. However, during subsequent operation after the integrity assessment, a number of time-dependent (e.g., corrosion, cyclic fatigue) and other factors (e.g., outside force damage) may act on the pipeline. These factors reduce the level of confidence in the pipe's integrity, as the time since the last integrity assessment increases. By providing operators ten years instead of seven to conduct 1 he baseline assessments and allowing an extra five years between subsequent assessments, the likelihood that a failure will occur in these locations is increased. This increase in risk would be small (statistically, much less than one incident per year) - primarily because the total mileagc : of pipe affected by this rule is not large and pipeline failure rates are already relatively low, Nevertheless, RSPA believes that sensitive environmental resources and populated areas neai pipeline facilities operated by operators with less than 500 miles of pipeline should be afford1:d the same protection as those resources and populated areas near pipelines operated by operatcm with 500 or more miIes of line. Since there is no compelling technical or practical justification for different requirements for this set of operators, the rule contains the same integrity assess nent requirements as the final rule recently established for operators with 500 or more miles of pipe (65 FR 75378). 34#

Page 38F. Environmental Justice Considerations In accordance with Executive Order 12898 (Federal Actions to Address Environmental Justia in Minority and Low-Income Populations), RSPA has considered the effects on minority and low-income populations of the provisions of this rule. The testing and other integrity management activities of this rule will enhance safety and environmental protection for high consequence areas. High consequence areas include regions near pipeline facilities that are populated, or have a commercially navigable waterway or an Unusually Sensitive Area. The USA definition identifies drinking water and ecological resources that may be unusually sensi1;ive to damage from an oil spill. The rule applies to all high consequence areas nation-wide, and d )es not specifically target any communities. Additional protection afforded populated areas will benefit all citizens in proximity to hazardc )us liquid pipelines, regardless of their economic or minority status. Any additional protection of ecological resources may provide some indirect benefits to communities in proximity to such resources, in addition to the national and global benefits. However, these benefits will be realized regardless of a community's economic or minority status. Therefore, the new integri1.y management rule for operators who operate 500 or less miles of pipeline does not have disproportionately high or adverse health or environmental effects on any minority or low-income populations near oil pipeline facilities. 35#

Page 39G. Information Made Available to States, Local Governments, and Individuals RSPA has made the following documents publicly available, and incorporates them by reference into this environmental assessment: “Regulatory Evaluation: Pipeline Integrity Management in High Consequence Areas (Hazardc us Liquid Pipeline Operators with less than 500 miles of Pipelines),” Docket RSPA 00-7408, September, 2001. “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators with less than 500 miles of Pipelines),” 66 FR 15821, March 21, 2001 “Pipeline Safety: Areas Unusually Sensitive to Environmental Damage,” 65 FR 80530, December 21, 2000. “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Hazardous Liql lid Operators with 500 or More Miles of Pipeline),” 65 FR 75378, December 1,2000. “Environmental Assessment: Final Rule, Pipeline Integrity Management in High Consequenci? Areas for Hazardous Liquid Pipeline Owners or Operators Operating 500 or More Miles of Pipeline,” Docket RSPA 99-6355, November 2000. “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas,” Notice of Proposed Rulemaking, 65 FR 21695, April 24,2000. “EnvironmentaI Assessment: Proposed Rulemaking Integrity Management in High Consequence Areas for Hazardous Liquid Pipeline Operators Operating 500 or More Miles of Pipeline,” Docket RSPA 99-6355, April 2000. “Draft Regulatory Evaluation: Pipeline Integrity Management in High Consequence Areas,” Docket RSPA 99-6355, March 2000. “Pipeline Safety: Areas Unusually Sensitive to Environmental Damage,” Notice of Proposed Rulemaking, 64 FR 73464, December 30, 1999. “Pipeline Safety: Enhanced Safety and Environmental Protection for Gas Transmission and Hazardous Liquid Pipelines in High-Consequence Areas,” Notice Extending Comment Peric d and Establishing Electronic Public Discussion Forum, 64 FR 71713, December 22, 1999. “Environmental Assessment: Proposed Definition of Areas Unusually Sensitive to Environmental Damage (USAs),” Docket RSPA 99-5455, December 1999. 36#

Page 40“Pipeline Safety: Enhanced Safety and Environmental Protection for Gas Transmission and Hazardous Liquid Pipelines in High Consequence Areas,” 64 FR 56725, October 2 1, 1999. “Areas Unusually Sensitive to Environmental Damage,” Notice of Initiating Pilot Testing, 64 FR 38173, July 15, 1999. “Emergency Flow Restricting DevicedLeak Detection Systems,’’ Advance Notice of Proposec I Rulemaking, 59 FR 2802, January 19, 1994. “Environmental Assessment: Hydrostatic Testing of Certain Hazardous Liquid and Carbon Dioxide Pipelines,” Docket PS- 144, June 9, 1993. “Emergency Flow Restricting Devices Study,” Docket PS-133, 1991, 37#

Page 41H. List of Agencies and Persons Consulted During the process of developing the integrity management rule, RSPA interacted and consul1 ed with numerous organizations. These participants included: American Petroleum Institute Association of Oil Pipe Lines Independent Liquid Terminals Association National Association of Pipeline Safety Representatives National Association of Regulatory Utility Commissioners Environmental Defense Fund National League of Cities LEPC Information Exchange Safe Bellingham US Public Interest Research Group Pipeline Reform Coalition City of Fredericksburg, Virginia International Union of Operating Engineers 38#

Page 42I. Conclusion Hazardous liquid pipeline failures that significantly impact the environment occur infrequentl::. Nonetheless, RSPA believes additional assurance of system integrity is important for high consequence areas, and that the rule will improve protection in these locations, as well ensure consistency in maintaining this protection. This Environmental Assessment has considered thlz impacts of the provisions in the rule, and determined that a reduction in the risk associated wi. h pipelines operating in high consequence areas should be expected. However, because many oi the liquid pipeline operators that will be covered by this rule are already performing some of the baseline integrity assessment and other activities required by this new rule, and because the toI;al pipeline mileage impacted by the rule is limited, the impact is expected to be small. Therefore, RSPA has concluded that the modifications to 49 CFR 195 to validate pipeline integrity in hirl,h consequence areas for operators operating less than 500 miles of pipe will not have a significi nt environmental impact. 39#

Page 43J. References “In-Line Nondestructive Inspection of Pipelines,” NACE International, Publication 35 100, December, 2000. “Pipeline Safety Hearing: Inspection and Integrity Verification,” National Transportation Safc:ty Board, November 15-16,2000. “Analysis of DOT Reportable Incidents for Hazardous Liquid Pipelines, 1986 Through 1996,’’ MI Publication 1158, January 1999. “Assurance of Hazardous Liquid Pipeline System Integrity,” API Recommended Practice 1 1 2,9, August 1996. “Common Ground: Study of One-Call Systems and Damage Prevention Best Practices,’’ US DOT, August 1999. “Pressure Testing of Liquid Petroleum Pipelines,” API Recommended Practice 1 1 10, March, 1997. “Environmental Assessment of the Proposed Longhorn Pipeline System,” US EPA and US DOT, October 29, 1999. ‘‘Instrumented Intemal Inspection Devices,” US DOT, November 1992. “Pipeline Risk Management Manual,” W. Kent Muhlbauer, Gulf Publishing Company, 1996 “Regional Assessment of Aquifer Vulnerability and Sensitivity in the Conterminous United States,” Pettyjohn et al., EPA/600/2-91/043, August, 1991. 40#

Page 44Appendix 1 Environmental Impacts of Oil Spills The hazardous liquid pipeline industry operates more than 157,000 miles of pipeline and relakd facilities that transport products ranging from crude oil to refined products (e.g., diesel fuel ar d gasoline) to highly volatile liquids (e.g., ethylene and carbon dioxide). These pipelines traver ;e each of the fifty states, passing through all types of environments from coastal shores and wetlands, to prairies and deserts. The affected environment covered by this Environmental Assessment consists primarily of high consequence areas (as defined in Section D). Because these locations have yet to be mapped, they could occur in any area in the United States that i ,; in proximity to a hazardous liquid pipeline regulated under 49 CFR Part 195, “Transportation oj Hazardous Liquids By Pipeline.’’ For this reason, this appendix provides a general discussior , of the environmental impacts of oil and petroleum product spills on different environmental resources. 1.1 Characteristics of Oil “Oil” is a generic term used to describe a closely related series of complex hydrocarbon compounds that can range from gasoline to heavy solids. The various mixtures that constitutcm “crude oil” can vary greatly in their chemical composition. Because they consist of mixtures ,If thousands of hydrocarbon compounds, their physical properties such as color, specific gravit !I, and viscosity also vary widely. Oils are classified using specific gravity or the American Petroleum Institute gravity scale anld relative mobility. Crude oil is generally broken down into four groups: a Tar Sands - immobile oil. a a Heavy Oils - No. 6 fuel oil (MI gravity <20”). Medium Oils - most crude oils (MI gravities between 20” and 25”). Light Oils -jet fuel, gasoline, diesel, No. 2 fuel oil (API gravities >25”). The different types of oils behave differently during a spill. Due to their high volatility, light weight oils generally do not persist in the environment. The very light weight oils, gasoline and jet fuel, are the most toxic but they evaporate quickly, usually within one to two days after a spill. Diesel, which is slightly heavier, tends to leave a residue of up to one-third of the amount sg illed for several days. 41#

Page 45Medium-weight oils pose the greatest environmental risks to organisms because the compoun Is are more persistent, are biologically available, and have high toxicities. Evaporative losses ar: lower, with about 70 to 80% of the amount spilled remaining after twenty-four hours. The heavy weight oils are the most persistent oils. Degradation rates are very slow and they persist in sediments as tar balls or asphalt pavements. Animals generally have to be exposed lria a sediment pathway or through the food chain. General characteristics of the different types of oils can be summarized as follows: Volatility _ _ _ _ _ _ Solubility Toxicity Bioavailability Light Oils ~~ ~ ~ Rapid, significant evaporation. Very light oils have complete evaporation in 1 - 2 days. Light oils have up to -2/3 evaporative losses in 1-2 days. High water solubility. High acute toxicity fiom monoaromatic hydrocarbons (benzene, toluene, xylene). Little potential for bioaccumulation. ~ Medium Oils Evaporation rates in days, some residue does not evaporate at ambient temperatures. Low water solubility. Moderate acute and chronic toxicities fiom diaromatic hydrocarbons (naphthalenes). Moderate potential for bioaccumulation. ~ Heavy Oils Almost no loss by evaporation. Almost no water solubility. Potential for chronic toxicity fiom polynuclear aromatic hydrocarbons (phenanthrene , anthracene); little acute toxicity risk except that due to smothering. Potential for bioaccumulation via sorption onto sediments, otherwise not highly bioavai lable . 42#

Page 46Within each of these types of oil, the smaller, or lighter weight, compounds are the more toxic 1.2 Overview of Environmental Consequences The following discussion summarizes the potential environmental impacts of oil spills. This section is not intended to provide a comprehensive description of all possible environmental impacts resulting fiom oil spills; rather, the objective is to provide an overview of the more important environmental consequences. I .2.1 Surface Waters Spilled oil can pose serious threats to freshwater and ocean environments. The severity of impact of an oil spill, as well as the ability to recover from the spill, will depend on a variety of factoi-s including the location and quantity of oil released, the characteristics of the spilled oil, the characteristics of the area affected, and local weather conditions. Weathering Weathering is a series of chemical, physical and biological changes that occur when the crudc.: oil and petroleum products interact with the water environment. Some of the more important nalural weathering actions are described below. Spreading/dispersion occurs when wind and wave action spreads the oil over the surf ice of the water forming a thin film or slick. The speed at which this occurs depends on 1 he viscosity of the oil and prevailing conditions such as temperature, water currents, tida 1 streams and wind speeds. Slicks generally spread quickly to cover extensive areas of the water surface. After a few hours the slick will begin to break up and form narrow bai ids, or windrows, parallel to the wind direction. Dispersion occurs when the slick is hrtf er broken down into droplets, which are distributed throughout the upper layers of the water column. Evaporation occurs when the lighter oils volatilize and disperse into the atmosphere leaving the heavier components of the oil behind in the water. Evaporation is the single most important weathering process in the first several days of a spill. The amount of evaporation and the speed at which it occurs depend upon the volatility of the oil. Environmental factors affecting evaporation include the exposed area of the slick, wind speed, water surface roughness, air temperature, and formation of emulsions. Light, refined products like gasoline may evaporate completely within a very short time. Ir general, evaporation will remove 20 to 60% of a crude oil spill. Volatilization of th.: 43#

Page 47low-boiling aromatics can have an impact on marine life as these compounds are highl;q toxic. Oxidation occurs when oxygen combines with oil. Oxidation of the oil hydrocarbons -will form fatty acids and other water-soluble compounds promoting additional transport of organic materials from the oil film into the water. The process is aided by sunlight bul is very slow even in ideal conditions. It occurs mostly around the edges of the spill. Thicmk layers of high viscosity oil or emulsions may only partially oxidize to form dense, sticl,:y, black spheres (tar balls) which may linger in the environment. Biodegradation occurs when microorganisms in the water feed on the oil hydrocarbon,;. This process can partially or completely degrade oil to water soluble compounds and eventually to carbon dioxide and water. The main factors affecting biodegradation arrf the levels of nutrients in the water, the temperature, and the level of oxygen present. Since no oxygen is available within the oil itself, the process can only take place at the oil-w ater interface. Biodegradation tends to work best in warm water environments. To sustain biodegradation, nutrients such as nitrogen and phosphorus are sometimes added to thc: water to encourage the bacteria to grow and reproduce. Emulsification occurs when wave action causes the oil and water to combine, with on e ending up as small droplets suspended in the other. The formation of emulsions will cause the volume of the spill to increase between three and four times. Two types of emulsions may exist: water-in-oil and oil-in-water. Water-in-oil emulsions, or “chocl )late mousse,’’ are formed when strong wave action causes water to become trapped inside viscous oil. Mousse emulsions are very viscous and more persistent than the original oil. Emulsions cause oil to sink and disappear from the surface of the water while accumulating in the bottom sediments and lingering in the environment for months o even years. Even large spills of refined petroleum products, such as gasoline, in water evaporate quickly and may cause only short-term environmental effects. In contrast, crude oils, heavy fuel oils, and water-in-oil mixtures may cause widespread and long-lasting physical contamination of aquiI.tic habitats and shorelines. Location Oil spills in open bodies of water can be harmful to many forms of aquatic life because they prevent sufficient amounts of sunlight from penetrating and also reduce the level of dissolvc d oxygen in the water. Crude oil can render feathers and gills ineffective, so that birds and fish may die from direct contact with the oil itself. However, marine organisms have the ability to 44#

Page 48swim away from a spill by going deeper into the water or further out to sea, thus reducing the likelihood that they will be harmed. Unlike ocean spills that are dispersed by wind and wave action, oil spilled near the shoreline clr in rivers, lakes, or other calmer bodies of water typically concentrates and mixes with near-shc ,re waters or collects along shorelines. Oil deposited in near-shore sediments persists longer thar in ocean sediments, and is particularly persistent in low-energy, wetland habitats. High-energy, rocky shores tend to clean themselves with a matter of months, whereas soft-sediment lagoon;.;, marshes, and mangrove swamps act as long-term petroleum sinks. On cobble and sandy beaches, oil can sink deeply into the sediments and remain longer than on bare rocks. Sediment grain size and compaction determine the rate of oil penetration. In muddy sediments, only the upper few inches are penetrated. However, because there is generally little weathering in these environments, stranded oil can persist for many years. Heavy oiling of the shore can cause immediate, widespread death of plants and animals. The long-term effects are more subtle. The United States contains extensive developments of salt, brackish, and freshwater marsh systems, many of which serve as the primary food source for both the coastal and near shore ecosystems of the region. Marshes serve as nursery habitats and generally have a high diversity and density of animal and plant species. The impact of near shore oil spills on these bordering wetlands can be significant. When floating oil is pushed into the marsh by tidal or wave action, it adheres readily to the vegetation. The band of coating can vary widely depending on wave height but large, persistiznt slicks tend to coat the entire plant stem. If the marsh vegetation is thick, contamination by hc :avy oils can be restricted to the outer fringe of the marsh. Light oils can penetrate much deeper, generally to the limit of the tidal or wave influence. Fresh oils tend to slide down the stems j n warmer weather and pool on the sediments at the base of the plant. Weathered oils are more likely to stay on the vegetation. Medium-to-heavy oils pool onto the sediment surface, whilc the lighter oils can penetrate the top few inches of sediment and deeply into burrows. In extremc cases like the West Falmouth spill where high wind and waves mixed diesel deeply into the estuary sediments, studies have documented long-term (i.e., more than ten years) persistence of oil in both sediments and the food chain. In the past, the greatest impact of the oil spill on the marsh frequently resulted from the cleai iup efforts. Root systems were destroyed by trampling. Surface sediments were removed leavirig little to support new growth. The remaining oil mixed into deeper sediments, slowing the niitural weathering and removal process. Mobilized sediments smothered surrounding vegetation. Responders are now more sensitive to the possibility of causing harm; cleanup tends to be limited to the passive collection of the oil onto sorbents. 45#

Page 491.2.2 Groundwater Spilled oil may affect nearby streams or ponds or it may be absorbed by the soil and reach the water table. Since ground water levels in the U.S. are typically between ten and twenty meter,; from the land surface, and can be a little as three meters or less, the potential for groundwater contamination from a spill can be significant. The severity, duration, nature and extent of the impact on groundwater resources depend on a large number of interdependent factors including: Type and quantity of oil released, Rate of release, Land slope, Soil thickness and grain size, Underlying geology, Soil temperature, Precipitation, Distance to aquifer, Stability of water table, and Aquifer permeability and transmissivity. A release that contaminates groundwater would most likely be either a slow, undetected leak that occurs in an area where the leaking oil would not be easily observed at ground surface, or a pipeline rupture. The depth to which the oil would penetrate the subsurface in the event of a slow leak is most dependent on the volume discharged. The volume that actually reaches groundwater decreases with increasing vertical and horizontal distance to the aquifer. Oils released onto fractured bedrock or highly permeable sand and gravel migrate quickly. Less permeable materials like silt, clay or unfractured bedrock inhibit downward migration. If thc pipeline is buried below the water table and a leak or rupture occurs, there is a high probabiltty the groundwater will be affected regardless of the released volume. Once an oil spill has occurred, the oil flows through the soil’s unsaturated zone. Some resic ual oil will be absorbed by the soil particles. When the remaining oil reaches the water table, it forms a film which floats on the surface of the aquifer and is moved along with the general low of the water. Some oil will continue to be absorbed by the soil particles lying just above the 46#

Page 50water table. The hydrocarbon plume will move with the groundwater gradient at a slightly slower speed than the water; concentrations will be greatest near the top of the aquifer. As the oil starts to mix with the water, a selective and specific redistribution of molecular compounds between soluble and suspended fractions occurs, initially through the physical dissolution of the water-soluble compounds. These two fractions, soluble and insoluble, will have different proportions and concentrations of organic compounds. The soluble fraction wi 11 be predominately aromatic, substituted, and low aliphatic hydrocarbons, including fatty, carboxylic and naphthenic acids, phenols, and cresols. Higher concentrations of polycyclic and high-molecular-weight aliphatic hydrocarbons will be found in the suspended fraction. After two to seven days, additional water-soluble compounds will be formed as a result of chemical and biological oxidation. These oxidized hydrocarbons will contain substantial quantities of fatty and carboxylic acids and are considerably more toxic than the original unoxidized hydrocarbons. A large volume of groundwater downstream from the spill can become contaminated. The most serious impacts from such contamination include degradation of groundwater quality and impairment of drinking water supplies. Crude oil may have significant impacts to long-term water quality in ground water because the higher viscosity, sorbability, and specific gravity lrlake crude oil more likely to sink deeper into the ground water column, to resist natural dilution a~ id transport through flushing, and to be less likely to volatilize. Gasoline may also have serious impacts to drinking water quality for both ground water and surface water. The transport characteristics of benzene and methyl tertiary-butyl ether (MtBE) make it more likely to reac I a drinking water source in the event of a release. Some studies indicate that, depending on soi conditions, gasoline spills can reach deep ground water tables in a matter of hours or days. The presence of specific additives in refined oil products can result in additional environmer tal concerns. For example, MtBE is a volatile, organic chemical which is added to gasoline as s n octane enhancer and oxidizer. MtBE is used in more than 85% of reformulated gasoline, which accounted for approximately 30% of the gasoline used nationwide in 1997. Studies have identified significant air quality and public health benefits from the use of such reformulated gasoline. However, the potential environmental impact, and human health risk, from MtBE is currently being debated. MtBE is hydrophilic, does not readily bind to soil particles, and resists natural degradation. These qualities allow it to travel quickly and easily into underground Bater supplies. There have been a limited number of instances of significant contamination of drii king water sources due to leaks from petroleum storage tanks and pipelines. Between 5 and 10% of drinking water supplies in high oxygenate fuel use areas show at least detectable amounts oj' MtBE, with approximately 1 % showing levels above 20 ppb. 1.2.3 47#

Page 51While the very light oils seem to cause the least damage on water, the opposite seems to be tn1.e on land. Light weight oils tend to penetrate the top soil quickly, thus placing groundwater at I isk. The higher viscosities of the heavier oils make soil penetration difficult, thus slowing contamination. The significance, magnitude, and duration of soil impacts from a spill depend on a number of factors including: Type and quantity of oil released; 8 Depth of product penetration; 0 Soil properties and chemistry, including water content, porosity, texture and organic carbon content; Terrain features; and 0 Soil and air temperatures. Land oil spills more frequently involve refined petroleum products like gasoline or diesel fuel, than marine spills, which generally involve crude oil. Differences in chemical composition aind physical characteristics can lead to differing environmental 'impacts depending on the specific : oil involved in the spill. For example: In the absence of an ignition, a large crude oil release would result in more severe lon g- term impacts to land use because of the slower movement rates and lower volatilizati ,in. If ignition occurs, gasoline wilI impact a larger area and potentially cause more damage to land use. Gasoline is more likely to ignite than crude oil, and because of the rapid hei3t release and the wider spread from a comparable volume released, a gasoline fire wou'id be expected to result in greater damage than a fire involving crude oil. Environmental effects from a spill on land tend to be confined to the immediate vicinity of tl le spill. Spreading is generally limited to a migration to the lowest point in the area. Generallj,, losses due to evaporation will be limited and formation of emulsions is rare. Little physical change occurs in the oil unless it is left on the ground for an extended period. However, the spill may change the physical, chemical, and microbial properties of the soil thus decreasing vegetative fertility and productivity. Spills on unsaturated soil may produce boggy, barren areas. As the oil penetrates the soil, it coats the soil particles thus reducing the soil's infiltration capacity and aeration. The pH may be altered, creating alkaline or acidic soil conditions. There can be an immediate loss of veget ;I+ t' l0n 48#

Page 52due to smothering or toxic effects. This will lead to increased erosion and offsite sedimentatk In. Plant growth and revegetation of the area may be inhibited because of insufficient plant-avail: ble water and poor root aeration. This decrease in the area’s productivity may last years depending on the topography, environmental conditions, and remediation practices employed. Long-ten: 1 impacts depend on the removal of contaminated soils and the recovery rate of the affected ecosystems. 1.2.4 Air Ouality Air quality can be impacted through evaporation from oil spills. Volatile organic compounds (VOCs), possibly including hazardous air pollutants (HAPs), will be released under these conditions. VOCs are indirectly regulated by the EPA through the ozone standards included .n the National Ambient Air Quality Standards. HAPs of concem may include hexane, benzene., toluene, 2,2,4-trimethylpentene, xylene, and ethylbenzene. The evaporation of these volatile chemicals from oil spills can result in significant, localized, and short term air pollution in the immediate vicinity of the spill. Most of the hydrocarbons that evaporate quickly are the low molecular weight aromatics such as benzene, toluene, and xylene. These hydrocarbons are among the most toxic components of crude oil and refined products. Because of the localized presence of these volatile constituents, they are of concern mainly fur workers in the immediate vicinity of the spill. With gasoline spills, vapor concentrations abc ve 1,000 ppm can cause headaches, dizziness, weakness and loss of coordination; higher concentrations, above 5,000 ppm may cause loss of consciousness or coma. Depending on the specifics of the spill, including amount of product spilled, wind speed and localized soil permeability, some volatile chemicals may reach toxic concentrations above the immediatelq dangerous to life or health (IDLH) limits. In the presence of sunlight, the released hydrocarbons will react with oxygen in the air, through a process called photo-oxidation, and form carbon dioxide, various sulfur-oxygen compounds, and acids. If nitrogen oxides are present, some hydrocarbons may form ozone. Ozone formatior increases almost proportionally to hydrocarbon concentration. However, the various types of hydrocarbons differ significantly in their ability to react with nitrogen oxides. If the oil is bL med, either during a fire associated with a spill or as part of the cleanup process, the by-products (if incomplete combustion can contribute to air pollution and smog. 1.2.5 Biological Impacts The consequences of a spill on a specific biological system are dependent upon a number of different factors including the type and amount of oil spilled, the geology of the area, local meteorological conditions, the season, and the type and sensitivity of the biological commuriities 49#

Page 53likely to be affected. The chemical properties of the oil will strongly influence the impacts thi1.t can be expected in a particular habitat since both toxicity and longevity are dependent on the t:y-pe of oil spilled. For example, experiments with phytoplankton have found that light oils have ai 1 inhibiting effect on growth while the heavier oils have little effect; these differences appear to the linked to the percentage of water soluble compounds in the original hydrocarbon mix. The physical and meteorological conditions at the site affect where the oil will go and how quickly it will weather. The presence of migratory birds or mammals and the aggregation of individual:, for breeding or spawning are examples of seasonal behaviors that can influence the vulnerability ,if a biological community to an oil spill. Oil can harm fish, birds and mammals in several ways, including: 0 Physical contact: The main threat from spilled oils and emulsions is physical smothe: ing. The animals and plants most at risk are those that could come in contact with a contaminated water surface - marine mammals and reptiles, birds that feed by diving )f form flocks on the water, and marine life on shorelines. Other threats include hypothermia and drowning. When fur or feathers come into contact with oil, they car become matted and lose their insulating properties. As a result, birds and mammals n lay die of hypothermia. The risk of drowning increases for birds because the complex structure of their feathers that allows birds to float becomes damaged. e Toxicity: Oils are “toxic” in that they have the inherent potential to cause adverse effects in living organisms. However, the degree of toxicity is determined by the type of oil, concentration, duration of exposure, and sensitivity of the receptor organism. Sensiti lrity to toxic compounds varies greatly by species, by life stage within a species, and by individual. In general, younger stages are more sensitive than adults. Individual characteristics, like age, sex, and contamination history are important in determining I:he degree of impact. Toxic effects may be either acute or chronic. Acute toxicity is an immediate impact 1 hat leads to the death of the individual. Since the most toxic components in oil tend to rapidly evaporate, lethal concentrations leading to large scale mortalities are relatively rare, localized and short-lived. Chronic effects may not be evident immediately and nay not cause the death of the individual. However, they can impact the physiology, behavior, or reproductive capacity of the individual and may ultimately impact the survival rates of the species affected. Toxic effects can come from the inhalation, ingestion, or skin absorption of oil. Oil vapors can cause damage to the animal’s central nervous system, liver, and lungs. Ingestion of oil can reduce the animal’s ability to digest food by damaging cells in th ,: 50#

Page 54intestinal tract. Ingested oil can also create reproductive problems, such as depressed e :;g laying rates and reduced hatchling survival rates for birds. Bioaccumulation is the uptake of a contaminant by an organism directly from water or through the consumption of contaminated food. Individuals that live in contaminated environments may appear healthy but still contain elevated levels of petroleum compounds in their tissues. Bioaccumulation can result in chronic effects to the individual and may cause potential food chain problems for both mammalian and avian species. 0 Disruption ofecosystems: Effects can include the temporary displacement of some species, alterations in predator-prey interactions, changes in hunting or fishing locatio is, disruption of migratory patterns, and temporary or permanent loss of habitat. Secondxy impacts may occur in association with cleanup activities as a result of soil compactior , removal of trees and brush and additional loss of habitat. Differential mortality rates resulting from oil spills can impact the relationships between organisms in the food chain. Individual organisms may experience changes in food or other resource availability, a,; well as changes in competition and predation from other species. Even species that a e not directly in contact with oil can be harmed by a spill. Predators that consume contaminated prey can be exposed to oil through ingestion. Because oil contaminatiori, gives fish and other animals unpleasant tastes and smells, predators will sometimes re fuse to eat their prey and will begin to starve. On the population level, species that are dependent on affected prey or habitats will decline while opportunistic species may increase. The sensitivity of fish to oil spills varies by species and age. In general, fish are very sensitke to short-term acute exposures but are able to metabolize sub-lethal intakes. Fish can be affectei I through ingestion of oil or oiled prey, absorption of dissolved petroleum products through th: gills, or by changes in the ecosystem. Damage to fish eggs and larvae may also occur which can cause the smothering of eggs, interference with hatching, or developmental abnormalities. h'rany physiological abnormalities caused by exposure to crude oil have been documented. The youngest fish are most vulnerable to oil spills; older fish may have a mucous coating that he1 ps them resist contact with toxic oil constituents. Large fish kills are unusual in open water environments but enclosed habitats, such as lakes or marshes, may concentrate oil enough tc cause acutely toxic conditions. Birds experience a variety of effects when exposed to oil. The primary direct effect is the fc uling of plumage. Oil causes disruption of the fine structures that form the feathers, resulting in tlie loss of their water-repellent characteristics. The oiled plumage becomes matted which allow water to penetrate to the body surface, resulting in chilling and hypothermia and a loss of buoyancy. Birds can readily ingest oil during preening or by consuming contaminated prey. The 5 1#

Page 55effects of ingested oil include anemia, pneumonia, intestinal irritation, kidney damage, altered blood chemistry, decreased growth, and decreased production and viability of eggs. Anemia ii; normally the most severe effect and anemic birds cannot forage for food. The direct exposure of eggs to oil also has a high potential for damage with exposure in the early stages of incubatiori considered the most toxic. Terrestrial animals, if not initially trapped in the oil, can usually leave the area of a spill and gso to adjacent uncontaminated areas. In most cases, this behavior should minimize impacts such tl- at adverse effects are short-lived and insignificant. However, changes in the food chain or in th(: habitat could result in significant negative impact for localized populations if there are no oth,:r suitable areas in the vicinity. Fires or explosions associated with oil spills can pose an additional hazard to wildlife. While most biological communities have adapted to wildfires, petroleum-fed fires may bum hotter than other types of fires, which would increase the potential for long-term impacts. Such fires can result in immediate loss of individuals, reductions in population, and loss in biodiversity. Fires over rivers or streams can cause fish kills in the immediate and downstream areas due to chariiges in water temperature and consumption of the dissolved oxygen in the water. If the spill site i,; near populated areas, fire could pose an immediate threat to human health and safety as well. Rare species, small local populations, or species that are seasonally concentrated in the impai :ted habitat are the most likely to decline as a result of an oil spill. The time necessary for oil- damaged populations of animals and plants to recover is highly variable and the extent to whrch the biological recovery of a habitat can be accelerated is severely limited. 1.2.6 Human Health and Safety Impacts on human health and safety may occur in both the general public and occupational workers. The main health concern is from the known carcinogenicity of several oil componc.:nts including benzene, toluene, xylene, and lead. Exposure to toxic elements in oil may occur through direct exposure or consumption of oil-tainted food or contaminated drinking water. Public Health and Safety The potential impact on public health of the gasoline additive MtBE is a major area of investigation at the current time. As discussed earlier, instances of MtBE contamination of ground water have been identified in various locations throughout the country. In a few cascs, the contamination was severe enough to require the use of alternate dnnking water supplies (due to consumer odor and taste concerns. Currently there are no data on the effects on humans of drinking MtBE-contaminated water. In laboratory tests on animals, cancer and non cancer effects occurred at high levels of exposure. The tests were conducted by inhalation exposure or 52#

Page 56by introducing the chemical in oil directly to the stomach. Because the animals were not exposed through drinking water, there is significant uncertainty about the degree of risk associated wit1 1 human exposure to MtBE at the low concentrations typically found in drinking water. Howei er, these results support a concern for a potential human hazard. In December 1997, the EPA issued an advisory on MtBE in drinking water, recommending control levels for taste and odor acceptability. MtBE concentrations of 20 to 40 micrograms per liter or below should avert the unpleasant taste and odor effects for most people. Concentratil Ins in this range are 20,000 to 100,000 times lower than the range of exposure levels resulting in cancer and non cancer effects in rodents. This exposure margin is typical of those used in the establishment of the National Primary Drinking Water Standards for other chemicals. In September 1999, the EPA’s Blue Ribbon Panel recommended that the use of MtBE be reduccd substantially. The EPA is continuing to evaluate available information and is doing additional research to seek more definite estimates of the potential human health risks. Other more immediate human health effects from oil spills are possible but rare. Injury and death are possible, normally associated with occupational exposures during cleanup and dispi )sal activities, or a fire or explosion following the spill. While the probability of a fire or explosic )n in a populated area may be small, the consequences can be catastrophic. For example, in Jum 1999, a pipeline rupture near Bellingham, Washington discharged several thousand barrels oj * gasoline into a local creek. The spill spread downstream causing explosions and fires in the downtown area. Three people were killed and eight others were injured. Occuvational Health und Safetv Workers can be exposed to significant health risks if appropriate health and safety plans are 1 tot followed during cleanup and remediation operations. Sources of occupational risk range fro1 n those associated with heavy equipment operation to exposure to various chemicals. Inhalaticrn of certain petroleum vapors for short periods may cause nausea, eye irritation, increased blood pressure, headache, light-headedness, loss of appetite, poor coordination, and difficulty concentrating. In addition, the International Agency for Research on Cancer has determined than some heavy fuel oils possibly cause cancer in humans. Petroleum products meet the definition of a hazardous substance in OSHA’s Hazardous Waste Operations and Emergency Response (HAZWOPER) standard through their inclusion in DOT’S hazardous materi’als list (29 CFR 1910.120(a)(3)). Consequently, oil spill clean up workers md emergency responders are covered by HAZWOPER and must be trained accordingly. 1.2.7 Economic Impacts and Land Use 53#

Page 57The economic impacts of an oil spill can be harder to quantify than those discussed in earlier sections. Economic losses may be less observable and placing a value on noncommercial activities, like recreational fishing, can be difficult. Consideration of damage to “existence” or “nonuse” values, like the intrinsic beauty of a scenic beach, may be controversial. Economic impacts can include property damage, reduced property values, and short-term or permanent disruptions in specific industries. For example, marine spills can have a devastating effect on local fisheries. Boats and gear can be directly damaged and fish stocks can be temporarily depleted. Loss of market confidence may result in the public being unwilling to purchase marine products from the region irrespective of whether the seafood is actually tainkd. Shorelines and near shore areas also serve as major recreational and tourism resources. Oil spills, and their associated cleanup, can have major impacts on the quality of these resources. Oil spills on land can result in the contamination of vegetation, soil, crops, grazing lands, and recreational facilities. A small spill (two to five gallons) would most likely be confined to thc pipeline right-of-way but larger spills could potentially affect areas hundreds of feet from the pipe. The removal of contaminated materials would likely require the grading and removal o:f soil with a resulting loss of vegetation. The temporary disruption to actual land use or recreational activities as a result of cleanup operations could be significant but short-term in 1 nost cases. However, it is possible that the quality and value of the land or recreational resource c( iuld suffer long-term adverse effects due to the continued presence of contaminated materials or t’ie visual degradation of the area. 54#

Page 58References “Achieving Clean Air and Clean Water: The Report of the Blue Ribbon Panel on Oxygenates in Gasoline,” U.S. EPA, July 1999. “An Introduction to Coastal Habitats and Biological Resources for Oil Spill Response,” Natic nal Oceanic and Atmospheric Administration, Report No. HMRAD 92-4. “Calculating the Cost of Natural Resource Damage,” Rebecca Renner, Environmental Scienc ,: & Technology, February 1 , 1998. “Drinking Water Advisory: Consumer Acceptability Advice and Health Effects Analysis on Methyl Tertiary-Butyl Ether (MtBE),” U.S. EPA, EPA-822-F-97-009, December 1997. “Environmental Assessment of the Proposed Longhom Pipeline System,” US EPA and US COT, October 29, 1999. “Fate and Effects of Marine Oil Spills,” International Tanker Owners Pollution Federation. Fate of Pollutants in the Air and Water Environments, I. H. Suffet, 1977. Groundwater Contamination and Emergency Response Guide, J. H. Guswa & W. J. Lyman, Noyes Publications, 1984. “Marine Oil Spills: To Clean or Not To Clean? A Conversation with Michael Foster,” Environmental Review Newsletter, Vol. 3, No. 4, April 1996. “Oil and Nature,” U.S. Fish and Wildlife Service. “Oil Spill Response Handbook,” Oil-Spill-Web, FlemmingHvidbak. Oil Spills, Don Nardo, Lucent Books, 1990. “Olympic Pipeline Fire Incident Report,” U.S. National Response Team Sitrep One and Two, June 11, 1999. 5 5#

Page 59“Toxicological Profile for Automotive Gasoline,” U.S. Public Health Service Agency for Toxic Substances and Disease Registry, 1995. “Toxicological Profile for Fuel Oils,” U.S. Public Health Service Agency for Toxic Substanctis and Disease Registry, 1995. “Understanding Oil Spills and Oil Spill Response,” U.S. EPA, Publication 9200.5-1 05, July 1993. Various Specialist Reports from the “Yellowstone Pipeline Missoula to Thompson Falls Rerclute Environmental Impact Statement,” U.S.D.A. Forest Service, July 1999. . 56#