{"operation":"document","citation":"0900006480e93bf1","title":"U.S. DOT/PHMSA - Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"Document scope: Draft Regulatory Evaluation for PHMSA’s proposed amendment to 49 CFR Part 192 (adding § 192.476) requiring operators to consider and document internal corrosion prevention and mitigation when designing and constructing new and replaced gas transmission and gathering pipelines (passages: regulations-gov-attachment-0900006480e93bf1-node-1; node-4; node-5; node-11).\nMaterial conclusions and findings reported in the document: PHMSA estimates the rule’s annual impact would be less than $100 million and that it would not have significant adverse effects on the economy or a substantial number of small entities (passage: node-4; node-11). The analysis assumes costs attributable to the proposed rule would be minimal (passages: node-6; node-7). Estimated benefits from avoided direct incident consequences are between $7.8 million and $15.7 million over the first 20 years (passage: 0","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e93bf1.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e93bf1.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e93bf1","source_url":"https://downloads.regulations.gov/PHMSA-2005-22642-0002/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\n_______________________________________\nRegulatory Assessment\nwith\nRegulatory Flexibility Analysis\nPaperwork Reduction Act Analysis\nDraft Regulatory Evaluation\nNotice of Proposed Rulemaking--Pipeline Safety: Design and Construction\nStandards to Reduce Internal Corrosion in Gas Transmission Pipelines\n[Docket No. PHMSA-2005-22642]\nOctober 2005\nPrepared by\nEconomic and Industry Analysis Division\nVolpe National Transportation Systems Center\nResearch and Innovative Technology Administration (RITA)\nand\nOffice of Pipeline Safety\nPipeline and Hazardous Materials Safety Administration (PHMS0A)\nU.S. Department of Transportation\n1\n\n<<<PAGE 2>>>\n\nDrait Regulatory Impact Assessment\nRegulatory Analysis\nIntroduction\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) is proposing\nregulations on the control of internal corrosion when designing and constructing new and\nreplaced gas transmission pipelines. The proposed rule would require an operator to\nconsider the potential for accumulating liquids that could result in internal corrosion and\nto take steps in design and construction that would reduce the risk. The proposed rule\nwould also require an operator to design and construct pipelines to mitigate the impact\nof internal corrosion that may occur. These proposed changes would facilitate steps tha\noperators are already required to take in operating and maintaining their pipelines to\nprevent or mitigate internal corrosion.\nNeed for the Action\nInternal corrosion has been one of the three leading causes of reportable incidents in gas\ntransmission pipelines for the past five years, both in terms of percentage of incidents and\ntheir consequences (see Tables 1 and 2). In fact, in 2003 and 2004, internal corrosion\ncaused more property damage than the other two most frequent causes, third party\nexcavation damage and external corrosion, combined.\nTable 1: Percentage of Total Natural Gas Transmission System Incidents for the\nThree Leading Causes\nCause / Year\n2000\n2001\n2002\n2003\n2004\n2005**\n(% of Total Incidents)\nExternal corrosion\n18\n8\n9\n12\n12\n10\nInternal corrosion\n20\n19\nExcavation damage\n25*\n43*\n18\n21\n*In 2000 and 2001, number includes all incidents attributable to outside force damage plus\n** 2005 data reported as of 10/14/2005.\nexcavation damage.\nSource: PHMSA, Incident Reporting Form 7100.2\nData as of 10/14/2005\nTable 2: Amount of Property Damage for Gas Transmission System Incidents for\nthe Three Leading Causes (in Millions of Dollars)\nCause / Year\n2000\n2001\n2002\n2003\n2004\n2005**\n(in Million $)\nExternal corrosion\n$3.5\n$2.0\n$4.1\n$8.4\n$1.6\n$88.7\nInternal corrosion\n$2.6\n$3.3\n$4.0\n$14.9\n$4.9\n$4.2\nExcavation damage\n$3.2*\n$14.9*\n$1.1\n$3.5\n$2.4\n$1.3\n2\n\n<<<PAGE 3>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\n*In 2000 and 2001, number includes all incidents attributable to outside force damage plus\nexcavation damage where appropriate.\n** 2005 data reported as of 10/14/2005. A single incident in 2005 caused $87.5 million in\nproperty damage.\nSource: PHMSA, Incident Reporting Form 7100.2\nData as of 10/14/2005.\n.\nA variety of options exist for the control of internal corrosion. Those options include\ncontrolling the quality of the gas in the pipeline, inspecting the inside of pipe visually,\nusing ultrasound to ascertain pipe wall thickness, using drips to remove liquids in the gas\nstream, using “slam valves” to cut off the flow of gas when high levels of contaminants\nare detected, and using alarms to warn when high levels of contaminants are detected.1\nTo be effective, any drips would need to be drained periodically. A complete internal\ncontrol program might use a mix of these options, supplemented and complemented by\nother measures, such as cleaning pigs, inhibitors, internal coatings on pipe, and gas\ndewatering.2\nCurrently, pipeline safety regulations found in 49 CFR Part 192 require that operators\nestablish and implement programs to prevent or mitigate internal corrosion in the\noperation and maintenance of gas transmission pipelines. In addition, the recent integrity\nmanagement regulations require operators to assess the integrity of their pipelines with\nrespect to internal corrosion. There are no Federal requirements that require pipelines to\nbe designed and constructed with the need to control internal corrosion in mind.\nIncluding such requirements would facilitate corrosion control measures in an operating\npipeline. In addition, the National Transportation Safety Board recommended the\nissuance of Federal design and construction standards for internal corrosion control.\nRationale for Regulatory Assessment\nAll proposed and final Federal regulations must undergo economic analysis. Executive\nOrder 12866 directs all Federal agencies to develop both preliminary and final regulatory\nanalyses if their proposed regulations are likely to be “significant regulatory actions” that\nmay have an annual impact on the economy of $100 million. The Order also requires a\ndetermination as to whether a proposed rule could adversely affect the economy or a\nsection of the economy in terms of productivity and employment, the environment, public\nhealth, safety, or State, local or tribal governments. In accordance with the regulatory\nphilosophy and principles provided in Sections 1(a) and (b) and Section 6(a)(3)(C) of\nExecutive Order 12866, an economic analysis of the proposed regulatory changes must\nbe conducted. Furthermore, the Regulatory Flexibility Act of 1980, as amended, requires\nFederal agencies to conduct a separate analysis of the economic impact of proposed rules\non small entities.\n1 NTSB Pipeline Accident Report, NTSB/PAR-03/01, pp. 21, 22.\n2 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” Cost of Corrosion, FHWA\nReport FHWA-01-156, April 2005, pp. E-15 to E-16, www.corrosioncost.com/home.html.\n3\n\n<<<PAGE 4>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nIn accordance with the above directives, PHMSA has performed a preliminary evaluation\nof the potential compliance costs of the proposed rule and feasible regulatory options and\nidentified those benefits that can be expressed in monetary terms. To the extent\npracticable, this is based on the available data and information from a range of pertinent\nsources. PHMSA estimates that the impact of implementing the rule would be less than\n$100 million annually, and that the rule would not adversely affect the economy or a\nsection of the economy in terms of productivity and employment, the environment, public\nhealth, safety, or State, local or tribal governments. This proposed rule is not considered\nsignificant under the Regulatory Policies and Procedures of the Department of\nTransportation (44 FR 11034, February 26, 1979). PHMSA has also determined, as\nrequired by the Regulatory Flexibility Act, that the proposed rule would not have a\nsignificant economic impact on a substantial number of small entities in the United\nStates.\nAlternatives Considered\nThe goal of this rulemaking is to reduce natural gas transmission system incidents\nresulting from internal corrosion. In developing the rulemaking, PHMSA considered the\nfollowing two alternatives:\n• Do Nothing.\n• Amend the pipeline safety regulations to add design and construction standards to\nreduce internal corrosion in gas transmission pipelines.\nGiven the NTSB’s recommendation P-03-1 concerning adding new regulations requiring\nthat new or replaced pipelines be designed and constructed in a manner that would\nmitigate internal corrosion (see above), and PHMSA’s concurrence with that\nrecommendation, PHMSA believes that it is necessary and appropriate to pursue a\nFederal rulemaking. Therefore, “Do Nothing” is not viewed by PHMSA as a viable\nalternative. It is developed no further in this regulatory evaluation.\nEconomic Analysis\nIn its proposed rule, Design and Construction Standards to Reduce Internal Corrosion in\nGas Transmission Pipelines, PHMSA is amending 49 CFR Part 192 by adding a new\nsection, § 192.476, mandating that operators consider internal corrosion risk when\ndesigning and constructing gas transmission pipelines. The new section would include\nthe following:\n• Performance tests for design and construction measures to control internal\ncorrosion.\n• A requirement that an operator consider whether it should install liquid removal\nequipment or corrosion monitoring devices on existing pipeline downstream of\nnew or replaced pipeline.\n4\n\n<<<PAGE 5>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\n• A requirement that an operator record the decisions it makes with respect to\ninternal corrosion control when designing and constructing pipelines.\nIn the remainder of this section, the impacted industry would be identified, and then the\neconomic impact of the proposed rule would be considered.\nImpacted Industries, Including Identification and Characteristics of the Potentially\nAffected Industries\nThe proposed rule would apply to new or replaced pipe and components on all natural\ngas transmission pipelines whose safety is regulated under 49 CFR Part 192. In addition,\nthe requirements would apply to gathering lines. The operators of natural gas\ntransmission pipelines are generally large firms. The operators of gathering lines are not,\nhowever (i.e., some are small entities).\nThe following table shows the salient characteristics of the natural gas transmission\npipelines impacted by the proposed rule.\nTable 3. Salient Characteristics of Natural Gas Transmission Pipelines and\nGathering Lines\nCharacteristic Value\nNumber of operators 903\nTotal natural gas transmission and gathering\npipeline mileage\n322,836*\nEstimated onshore annual new and\nreplacement mileage\n2,506*\nEstimated offshore annual new and\nreplacement mileage\n325*\nTotal annual new and replacement mileage\nexpected to be impacted by the proposed rule\n2,831\n*Mileage information submitted by 903 operators in 2004 Annual report\nsubmitted in 2005.\nSource: PHMSA, 2004 Annual reports for gas transmission and gathering\nsystems PHMSA 7100.2-1\nThe proposed rule would not impact the full 322,836 miles of natural gas transmission\nand gathering lines. Rather, only new or replaced pipeline would be subject to the\nproposed rule. To estimate the new and replacement mileage information in Table 3, this\nanalysis used the total mileage of onshore and offshore pipes installed during 2000-2004\nfrom the annual reports and assumed that, on average (total mileage divided by 5 years\n2000-2004) operators would continue to add or replace pipes at the same rate in future.\nFor example, total onshore transmission and gathering lines installed during 2000-2004\nwere reported as 12,530 miles. The analysis assumed that during the period 2000-2004\n5\n\n<<<PAGE 6>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nthis mileage represents the new or replacement pipes. Therefore, on average 12,530/5 or\n2,506 per year is the estimated onshore transmission plus gathering miles that would be\nsubject to the proposed rule. Similarly, 1,624 miles of offshore transmission and\ngathering lines were installed during this period (2000-2004), therefore, 1,624/5 or 325\nmiles per year of offshore transmission and gathering lines would be subject to the\nproposed rule. The total annual estimate is the sum of the onshore and offshore annual\nestimates of natural gas transmission and gathering miles or (2,506+325) = 2,831 miles of\nnew or replacement pipes per year.\nImpact of the Proposed Regulations\nPHMSA’s proposed rule would impact the internal corrosion control activities of gas\ntransmission and gathering lines. Those activities make pipeline operations safer by\nhelping to reduce the number of incidents. The regulations proposed by PHMSA may\nresult in added costs related to internal corrosion control that would be borne by pipeline\noperators and added benefits that include a reduction in the number of incidents. The\nregulations should also facilitate future operation and maintenance efforts on the new and\nreplaced lines that have been designed with corrosion in mind.\nCosts\nThe costs attributable to the proposed rule would be any associated with\n• The design and construction of new and replaced pipeline to control internal\ncorrosion,\n• Operation and maintenance activities required due to designing pipeline to control\ninternal corrosion,\n• Actions taken to modify existing pipeline downstream of and impacted by new or\nreplaced pipeline, and\n• Record keeping.\nThe remainder of this cost section addresses the potential costs related to pipeline design,\nconstruction, downstream modification, and record keeping.\nDesign – The costs attributable to designing new or replaced pipeline to meet the\nprevention and mitigation requirements of the proposed rule would be nominal. When\npipeline operators add or replace pipeline, they already go through a design process, and\nthe design teams include individuals with corrosion expertise. There is no evidence to\nindicate that mandating the inclusion of internal corrosion prevention and mitigation in\nthe design of a pipeline would materially impact the cost of this process.\nConstruction3 – The costs attributable to constructing new or replaced pipeline that meets\nthe prevention and mitigation requirements of the proposed rule are unknown. They\ncould vary from $0 on up, depending on such things as the nature of the gas that would\n3 For an overview of the construction process applicable to transmission pipelines, see\nprimis.phmsa.dot.gov/pipelineInfo/const_overview.htm.\n6\n\n<<<PAGE 7>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nbe transported, the terrain, and control and monitoring devices, if any, that would be\nused. Most new or replaced pipeline would be constructed exactly as it would have in the\nabsence of the proposed rule, because terrain and operating conditions are similar to\nadjoining pipeline, and internal corrosion is not a high risk threat for that adjoining\npipeline. For pipeline that is constructed differently than it would have been in the\nabsence of the proposed rule, the changes are expected to be relatively minor (e.g., the\naddition of drips at strategic locations). These relatively minor changes are expected to\nresult in equally minor additions to construction costs. For the purposes of this analysis,\nthe construction costs attributable to the new rule are assumed to be minimal.\nOperation and Maintenance – The operation and maintenance (O&M) costs attributable\nto operating new or replaced pipeline that meets the prevention and mitigation\nrequirements of the proposed rule are unknown. Most new or replaced pipeline would be\noperated and maintained exactly as it would have been in the absence of the proposed\nrule, because terrain and operating conditions are similar to adjoining pipeline, and\ninternal corrosion is not a high risk threat for that adjoining pipeline. Changes in O&M\ndue to the proposed rule are expected to be relatively minor (e.g., if the proposed rule\nresults in the addition of a drip on a new or replaced line, then an O&M impact would be\nthat the drip would need to be cleaned periodically). The changes in O&M due to the\nproposed rule are expected to result in relatively minor additional costs. For the purposes\nof this analysis, O&M costs attributable to the new rule are assumed to be minimal.\nDownstream Modification – The costs attributable to modifying existing downstream\npipeline that may be impacted by new or replaced pipeline are unknown. The proposed\nrule requires consideration of the impact on downstream pipeline. It is left up to the\noperator to decide whether to make any modifications. Presumably, that would be a\nbusiness-based decision that would have been the same even in the absence of the\nproposed rule. For the purposes of this analysis, the modification costs attributable to the\nnew rule are assumed to be minimal.\nRecord keeping – The cost of record keeping resulting from the proposed regulation\nwould be nominal, if any. Records relating to pipeline design, construction, operation,\nand maintenance are already being kept by operators. 49 CFR Part 192 recordkeeping\nrequirements currently apply to all operators transporting natural and other gas by\npipeline under PHMSA jurisdiction. Prudent business practice also requires that pipeline\noperators keep pipeline design and construction records. Those records would be created\nfor design and construction purposes, of course, but could satisfy the requirements of the\nNPRM with minimum, if any, additional burden to the industry. Additionally, 49 CFR\n192.605(b)(3) requires procedures be established for “[m]aking construction\nrecords…available to appropriate operating personnel.” To do this, of course, those\nconstruction records must be maintained by operators already. Furthermore, 49 CFR\n192.491 requires the maintenance of records “…to demonstrate the adequacy of corrosion\ncontrol measures or that a corrosive condition does not exist” is required. Therefore\nexisting recordkeeping requirements would support additional burdens, if any, of this\nNPRM.\n7\n\n<<<PAGE 8>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nOverall – Overall, it is assumed that the costs attributable to the proposed rule would be\nminimal. The corrosion control requirements embodied in the proposed rule would\nfunction primarily as a reminder of the importance of corrosion control, particularly\ncontrol of corrosion due to liquids. It would heighten the awareness of operators to the\nproblem of internal corrosion. Prudent business practices should already encourage\noperators to make all reasonable efforts to control internal corrosion. This would prevent\naccidents, protect the operator’s investment, improve reliability of the line, and reduce\nfuture maintenance costs.\nBenefits\nThe benefits of the proposed rule would include a reduction in the direct consequences of\ninternal corrosion incidents (i.e., a reduction in the deaths, injuries, property damage, and\nlost product directly attributable to internal corrosion incidents). It would also include\nother savings, such as those related to making future maintenance easier, increasing the\noperational life of pipe, and avoiding economic consequences of accident-induced supply\nrestrictions,4 legal costs,5 and reduced emergency response costs. In this analysis,\nhowever, only the expected reduction in the direct consequences is estimated.\nTable 4 presents a summary of the reported internal corrosion incident consequences on\nnatural gas transmission pipelines from 2000 through 2004.\nTable 4: Summary of Internal Corrosion Incident Consequences on Natural Gas\nTransmission Pipelines, 2000 to 2004\nYear Number of\nProperty\nInjuries Deaths\nincidents\ndamage\n(millions of $)\n2000 16 $2.6 2 12\n2001 9 $3.3 0 0\n2002 15 $4.0 0 0\n2003 13 $14.8 0 0\n2004 23 $4.9 0 0\nSource: PHMSA, ops.dot.gov/stats/stats.htm.\nThe values for 2000, it might be noted, include the internal corrosion incident that\noccurred at Carlsbad, New Mexico, on an El Paso Natural Gas pipeline.\n4 Final Regulatory Evaluation, Pipeline Integrity Management in High Consequence Areas (Gas\nTransmission Pipelines),” Docket RPSA-00-7666, for instance, estimated that, as a result of the Pipeline\nIntegrity Management in High Consequence Areas regulations, approximately $1 billion would be saved\nover 20 years as a result of reduced economic consequences of accident-induced supply restrictions.\n5 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” estimates that “[l]egal issues\nand liabilities” add between $100 million and $200 million per fatality and injury to the costs associated\nwith pipeline corrosion incidents.\n8\n\n<<<PAGE 9>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nThe Department of Transportation currently makes the following assumptions concerning\nthe value of a statistical life and the value of an injury requiring hospitalization:\n• The value of a statistical life is $3,000,000\n• Injuries requiring hospitalization are valued at $562,500.6\nIn addition, for the purposes of this analysis, the natural gas lost as a result of a reportable\nincident is assumed to be valued at $431 thousand.7\nOn average over the period from 2000 through 2004, the direct consequences of internal\ncorrosion incidents on gas transmission pipelines cost $0.06 million per thousand miles\nper year.8\nThe proportion of the direct incident consequences that the proposed rule would prevent\nis unknown. For the purposes of this analysis, it is assumed that the proposed rule would\nprevent between 50 and 100 percent of the direct incident consequences. If 50 percent of\nthe direct incident consequences are avoided, then the benefits of the proposed rule would\nbe $7.8 million over the first 20 years. If 100 percent of the incident consequences are\navoided, then the benefits of the proposed rule would be $15.7 million over the first 20\nyears.9 Thus, it is estimated that the benefits resulting from the proposed rule would save\nbetween $7.8 million and $15.7 million over the first 20 years after the proposed rule is\nissued. This represents the savings attributable only to reduced direct incident\nconsequences.\nComparison of Benefits and Costs\nAs stated above, the proposed regulatory change is assumed to result in minimal costs.\nBenefits are estimated at between $7.8 million and $15.7 million over the first 20 years\nfollowing implementation of the proposed rule. These benefits focus exclusively on\navoided direct consequences of incidents (i.e., deaths, injuries, property damage, and lost\nproduct), and do not include other potential benefits, such as avoided economic\nconsequences of accident-induced supply restrictions, avoided legal costs, reduced\nemergency response costs, or increased operational life of pipe.\n6 The average injury requiring hospitalization is assumed to be a “Severe injury,” as defined by the U.S.\nDepartment of Transportation. The cost to society of a “Severe injury” is assumed to be equal to 0.1875\ntimes the cost to society of a lost life.\n7 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” estimates that a corrosion\nincident results in lost product valued at between $287 thousand and $574 thousand. The $431 thousand\nestimate used here is midway between these two values.\n8 In deriving this estimate, the property damage reported in Table 4 was the Producer Price Index, All\nCommodities, Base=2004. The source of the price index information used here was U.S. Department of\nLabor, Bureau of Labor Statistics, Producer Price Index, All Commodities, 1982=100, which can be found\nat www.bls.gov/ro9/9320.pdf.\n9 This is the net present value of avoided direct consequences calculated using a 7 percent discount rate.\n9\n\n<<<PAGE 10>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nFor the proposed rule not to be cost-beneficial, costs would need to be in excess of $1.48\nmillion per year. This would result in total costs in excess of the $15.7 million upper\nlimit on benefits. They would need to be approximately $736 thousand per year to be in\nexcess of the $7.8 million lower limit on benefits.10\nConclusion\nPHMSA believes that the proposed rule represents the most cost-effective alternative for\nensuring internal corrosion control on gas transmission pipelines. Furthermore, PHMSA\nexpects that the proposed rule would have a positive net benefit for pipeline operators,\npublic safety, and the public environment.\n10 For this comparison, it is assumed that all costs are incurred in the year in which new or replaced pipeline\nis installed. O&M costs, if any, may be incurred in subsequent years, but it is not possible to say what\nthose recurring O&M costs might be.\n10\n\n<<<PAGE 11>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nRegulatory Flexibility Analysis\nThe Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires an agency to review\nregulations to assess their impact on small entities unless the agency determines that a\nrule is not expected to have a significant impact on a substantial number of small entities.\nThe design and construction standards rule would not have a significant impact on a\nsubstantial number of small entities.11\nNeed for the Final Rule: PHMSA presently has regulations relating to internal corrosion\nprevention applicable to natural gas transmission pipeline operators. Those regulations\nare found in 49 CFR 192. PHMSA believes that additional regulations enhancing these\nexisting regulations are necessary to give further guidance to pipeline operators.\nDescription of Actions: In the Notice of Propose Rulemaking, PHMSA is proposing to\namend the Federal pipeline safety regulations by requiring operators to consider the\ncontrol of internal corrosion when designing and constructing new and replaced gas\ntransmission pipelines.\nIdentification of potentially affected small entities: For the purposes of the current\nanalysis, it is assumed that the proposed changes in the regulations would impact an\nestimated of 903 operators. Those operators consist of gas transmission and gathering\nsystems. Of the gas transmission system operators impacted by the proposed rule, none\nare small entities. Some gas gathering system operators may be small entities. The exact\nnumber of gas gathering system operators that are small business according to the Small\nBusiness Administration’s threshold of $6 million in revenue or 1,500 in employee size is\nunknown, but it is not substantial.\nCompliance, reporting, and recordkeeping requirements: This Notice of Proposed\nRulemaking includes new compliance requirements. Impacted pipeline operators would\nbe required to consider the potential that accumulating liquids could result in internal\ncorrosion and to take steps during design and construction that would reduce the risk.\nPrevention and mitigation on the new or replaced pipeline, and the impact of the actions\ntaken on downstream pipeline must all be considered. Operators must document all\ndesign and construction decisions relating to the prevention and mitigation of internal\ncorrosion. The costs of these actions are expected to be minimal.\nRelated Federal rules and regulations: Existing rules relating to internal corrosion\nprevention on gas transmission pipelines can be found in 49 CFR 192. With respect to\nthe safety of the transportation of natural gas by pipeline there are no related rules or\nregulations issued by other departments or agencies of the Federal Government.\n11 As defined by the Small Business Administration, small entities in the pipeline industry, have either\nfewer than 500 employees or less than $6 million in revenue, depending on the particular NAICS (North\nAmerican Industry Classification System) industry into which the entity falls. For more information, see\nwww.sba.gov/size/index.html.\n11\n\n<<<PAGE 12>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\nAlternate proposals for small businesses: The Regulatory Flexibility Act directs agencies\nto establish exceptions and differing compliance standards for small businesses, where it\nis possible to do so and still meet the objectives of applicable regulatory statutes. In the\ncase of corrosion prevention, no exceptions for small businesses are proposed.\nConclusion: Based on available information, it can be concluded that, this Notice of\nProposed Rulemaking does apply to some small entities (i.e., to some gas gathering\nsystem operators), but it would not result in a significant economic impact on any small\nentities.\n12\n\n<<<PAGE 13>>>\n\nD D Dr r ra a af f ft t t R R Re e eg g gu u ul l la a at t to o or r ry y y I I Im m mp p pa a ac c ct t t A A As s ss s se e es s ss s sm m me e en n nt t t\n13","truncated":false,"body_characters":28821}