{"operation":"document","citation":"0900006480e93bef","title":"U.S. DOT/PHMSA - Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas Transmission Pipelines - Final Regulatory Evaluation","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n _______________________________________ Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis Final Regulatory Evaluation Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas... F F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n be designed and constructed with the need to control internal corrosion in mind. This rule addresses the risk of internal corrosion at the earliest stage possible, applying accepted...","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e93bef.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e93bef.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e93bef","source_url":"https://downloads.regulations.gov/PHMSA-2005-22642-0024/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\n_______________________________________\nRegulatory Assessment\nwith\nRegulatory Flexibility Analysis\nPaperwork Reduction Act Analysis\nFinal Regulatory Evaluation\nPipeline Safety: Design and Construction Standards to Reduce Internal\nCorrosion in Gas Transmission Pipelines\n[Docket No. PHMSA-2005-22642]\nMarch 2007\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 (PHMSA)\nU.S. Department of Transportation\n1\n\n<<<PAGE 2>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\nRegulatory Analysis\nIntroduction\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) is adopting\nregulations on the control of internal corrosion when designing and constructing new and\nreplaced gas transmission pipelines. The rule requires an operator to consider the\npotential for accumulating liquids that could result in internal corrosion and to take steps\nin design and construction that would reduce the risk. The rule also requires an operator\nto design and construct pipelines to mitigate the impacts of internal corrosion that may\noccur. These changes facilitate steps that operators are already required to take in\noperating and maintaining their pipelines to prevent or mitigate internal corrosion.\nNeed for the Action\nIn 2003, the National Transportation Safety Board (NTSB) recommended the issuance of\nFederal design and construction standards for internal corrosion control (see NTSB\nrecommendation P-03-1). The NTSB recommendation arose out of its investigation of\nthe August 19, 2000 gas transmission pipeline incident near Carlsbad, New Mexico. The\nNTSB concluded that the immediate cause of the Carlsbad incident was a pipeline failure\ncaused by severe internal corrosion. The NTSB issued a final report, recommending (1)\nrulemaking to require that new and replaced gas transmission pipelines be designed and\nconstructed with features to mitigate internal corrosion; (2) development of requirements\nfor gas operators to address the role of water in their internal corrosion control programs;\nand (3) changes to Federal inspection to ensure adequate assessments of pipeline operator\nsafety programs. PHMSA has already completed action on the second and third\nrecommendations. This rule completes action on the first recommendation.\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\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.\n2\n\n<<<PAGE 3>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\nbe designed and constructed with the need to control internal corrosion in mind. This\nrule addresses the risk of internal corrosion at the earliest stage possible, applying\naccepted understandings about the causes and prevention of corrosion. The requirements\nof this rule improves the ability of the operator to prevent internal corrosion and\nfacilitates maintenance activities to control internal corrosion.\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 rule could adversely affect the economy or a section of the\neconomy in terms of productivity and employment, the environment, public health,\nsafety, 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 regulatory changes must be\nconducted. Furthermore, the Regulatory Flexibility Act of 1980, as amended, requires\nFederal agencies to conduct a separate analysis of the economic impact of their rules on\nsmall entities.\nIn accordance with the above directives, PHMSA has performed an evaluation of the\npotential compliance costs of the rule and feasible regulatory options and identified those\nbenefits that can be expressed in monetary terms. To the extent practicable, this is based\non the available data and information from a range of pertinent sources. PHMSA\nestimates that the impact of implementing the rule would be less than $100 million\nannually, and that the rule would not adversely affect the economy or a section of the\neconomy in terms of productivity and employment, the environment, public health,\nsafety, or State, local or tribal governments. The rule is not considered significant under\nthe Regulatory Policies and Procedures of the Department of Transportation (44 FR\n11034, February 26, 1979). PHMSA has also determined, as required by the Regulatory\nFlexibility Act, that the rule will not have a significant economic impact on a substantial\nnumber of small entities in the United States.\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.\n3\n\n<<<PAGE 4>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\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 rule, Design and Construction Standards to Reduce Internal Corrosion in Gas\nTransmission Pipelines, PHMSA is amending 49 CFR Part 192 by adding a new section,\n§ 192.476, mandating that operators consider internal corrosion risk when designing and\nconstructing gas transmission pipelines. The new section will include the 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.\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 is identified, and then the\neconomic impact of the rule will be considered.\nImpacted Industries, Including Identification and Characteristics of the Potentially\nAffected Industries\nThe rule will apply to new or replaced pipe and components on all natural gas\ntransmission pipelines whose safety is regulated under 49 CFR Part 192. In addition, the\nrequirements will apply to gathering lines. The operators of natural gas transmission\npipelines are generally large firms. The operators of gathering lines are not, however\n(i.e., some are small entities).\nThe following table shows the salient characteristics of the natural gas transmission\npipelines impacted by the rule.\nTable 3. Salient Characteristics of Natural Gas Transmission Pipelines and\nGathering Lines\nCharacteristic Value\nNumber of operators 1390\nTotal onshore natural gas transmission and\ngathering pipeline mileage\n300,755\nEstimated onshore annual new and 2,096*\n4\n\n<<<PAGE 5>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\nreplacement mileage – transmission\nEstimated onshore annual new and\nreplacement mileage – gathering lines\n166*\nTotal annual new and replacement mileage\nexpected to be impacted by the rule\n2,262*\n*Based on mileage information submitted by 1390 pipeline operators in their\n2005 annual reports to PHMSA.\nSource: PHMSA, 2005 Annual reports for gas transmission and gathering\nsystems PHMSA 7100.2-1\nThe rule will not impact the full 300,755 miles of onshore natural gas transmission and\ngathering lines estimated to in operation. Rather, only new or replaced pipeline will be\nsubject to the rule. To estimate the new and replacement mileage information in Table 3,\nthis analysis used the total mileage of onshore transmission pipes installed during 2000-\n2005 from the annual reports and the total mileage of onshore gathering lines during\n2000-2005, and assumed that, on average, operators would continue to add or replace\npipes at the same rate in future. Total onshore transmission pipe installed during 2000-\n2005 was reported as 12,578 miles, so the average installed each year over the six-year\nperiod from 2000 through 2005 was 2,096 (= 12,578 / 6). Total onshore gathering line\npipe installed during 2000-2005 was reported as 999 miles, so the average installed each\nyear over the six-year period from 2000 through 2005 was 166 (= 999 / 6). The analysis\nassumed that these mileages represent onshore new or replacement pipes for transmission\nand gathering systems, respectively. In total, the estimated additional onshore\ntransmission plus gathering line mileage that would annually become subject to the rule\nwould be 2,262 miles (= 2,096 miles + 166 miles). It should be noted that, with each\n2,262 mile increment, more and more pipeline would become subject to the rule over\ntime.\nImpact of the Rule\nPHMSA’s new rule will 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 rule may result in added costs related to\ninternal corrosion control that would be borne by pipeline operators and added benefits\nthat include a reduction in the number of incidents. The rule should also facilitate future\noperation and maintenance efforts on the new and replaced lines that have been designed\nwith corrosion in mind.\nCosts\nThe costs attributable to the rule will be any associated with\n• The design and construction of new and replaced pipeline to control internal\ncorrosion,\n5\n\n<<<PAGE 6>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\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• Recordkeeping.\nThe remainder of this cost section addresses the 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 rule will be nominal. When pipeline\noperators add or replace pipeline, they already go through a design process, and the\ndesign 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 will 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 rule are unknown. They could vary\nfrom $0 on up, depending on such things as the nature of the gas that would be\ntransported, the terrain, and control and monitoring devices, if any, that would be used.\nMost new or replaced pipeline would be constructed exactly as it would have in the\nabsence of the rule, because terrain and operating conditions are similar to adjoining\npipeline, and internal corrosion is not a high risk threat for that adjoining pipeline. For\npipeline that is constructed differently than it would have been in the absence of the rule,\nthe changes are expected to be relatively minor (e.g., the addition of drips at strategic\nlocations). These relatively minor changes are expected to result in equally minor\nadditions to construction costs. For the purposes of this analysis, the construction costs\nattributable 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 rule are unknown. Most new or replaced pipeline would be operated\nand maintained exactly as it would have been in the absence of the rule, because terrain\nand operating conditions are similar to adjoining pipeline, and internal corrosion is not a\nhigh risk threat for that adjoining pipeline. Changes in O&M due to the rule are expected\nto be relatively minor (e.g., if the rule results in the addition of a drip on a new or\nreplaced line, then an O&M impact would be that the drip would need to be cleaned\nperiodically). The changes in O&M due to the rule are expected to result in relatively\nminor additional costs. For the purposes of this analysis, O&M costs attributable to the\nnew 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 rule\nrequires consideration of the impact on downstream pipeline. It is left up to the operator\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\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\nto decide whether to make any modifications. Presumably, that would be a business-\nbased decision that would have been the same even in the absence of the rule. For the\npurposes of this analysis, the modification costs attributable to the new rule are assumed\nto be minimal.\nRecordkeeping –Records relating to pipeline design, construction, operation, and\nmaintenance are already being kept by operators. Prudent business practice requires that\npipeline operators keep pipeline design and construction records. Those records are\ncreated for design and construction purposes, of course, but could satisfy the\nrequirements of the rule with minimal, if any, additional burden to the industry.\nThe recordkeeping requirements currently included in 49 CFR Part 192 apply to all\noperators transporting natural and other gas by pipeline under PHMSA jurisdiction.\nThose requirements cover at least some of the records that would need to be kept under\nthe proposed regulations. For instance, 49 CFR 192.605(b)(3) requires procedures be\nestablished for “[m]aking construction records…available to appropriate operating\npersonnel.” To do this, of course, those construction records must be maintained by\noperators already. Additionally, 49 CFR 192.491 requires the maintenance of records\n“…to demonstrate the adequacy of corrosion control measures or that a corrosive\ncondition does not exist.” Therefore, existing recordkeeping requirements will also help\nminimize the additional burdens, if any, of the rule.\nAs a consequence of the foregoing, PHMSA expects the costs, if any, associated with the\nrecordkeeping requirements of the proposed regulations to be nominal.\nOverall – Overall, it is assumed that the costs attributable to the rule will be minimal.\nThe corrosion control requirements embodied in the rule would function primarily as a\nreminder of the importance of corrosion control, particularly control of corrosion due to\nliquids. It would heighten the awareness of operators to the problem of internal\ncorrosion. Prudent business practices should already encourage operators to make all\nreasonable efforts to control internal corrosion. This would prevent accidents, protect the\noperator’s investment, improve reliability of the line, and reduce future maintenance\ncosts.\nBenefits\nThe benefits of the rule will include a reduction in the direct consequences of internal\ncorrosion incidents (i.e., a reduction in the deaths, injuries, property damage, and lost\nproduct directly attributable to internal corrosion incidents). It will also include other\nsavings, 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.\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\n7\n\n<<<PAGE 8>>>\n\nFuel Regulatory Evaluation\ndamage are included in the table.\nTable 4: Summary of Internal Corrosion Incident Consequences on Natural Gas\nTransmission Pipelines, 2000 through 2005\nYear\nNumber of\nProperty\nInjuries\nDeaths\nincidents\ndamage\nTransmission\n2000\n5\n$1,479,196\n0\n2001\n3\n$1,015,850\n2002\n3\n$557,683\n2003\n3\n$6,045,720\n2004\n2\n$149,758\n2005\n3\n$282,034\nGathering\n2000\n3\n$172,000\n0\n2001\n3\n$2,000,000\n0\n2002\n1\n$45,000\n0\n2003\n1\n$127,000\n0\n2004\n1\n$600,000\n0\n2005\n2\n$718,500\n0\n0\nCompressor Stations\n2000\n0\n2001\n0\n0\n2002\n0\n0\n0\n2003\n2\n$7,363,000\n0\n0\n2004\n0\n0\n2005\n0\nTotal - All Categories\n2000\n8\n$1,651,196\n0\n0\n2001\n6\n$3,015,850\n0\n2002\n4\n$602,683\n0\n2003\n6\n$13,535,720\n2004\n3\n$749,758\n0\n2005\n5\n$1,000,534\n0\n0\nSource: PHMSA, transmission system incident reports\n8\n\n<<<PAGE 9>>>\n\nFuel Regulatory Evaluation\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.\nthe value of a statistical life and the value of an injury requiring hospitalization:\nThe Department of Transportation currently makes the following assumptions concerning\n•\nThe value of a statistical life is $3,000,000\n• Injuries requiring hospitalization are valued at $562,500.°\nincident is assumed to be valued at $431 thousand.?\nIn addition, for the purposes of this analysis, the natural gas lost as a result of a reportable\nOn average over the six-year period from 2000 through 2005, the direct consequences of\ninternal corrosion incidents on 300,755 miles of onshore transmission and gathering\npipelines cost $40 per mile per year.®\nThe proportion of the direct incident consequences that the rule will prevent is unknown.\nFor the purposes of this analysis, it is assumed that the rule will prevent between 50 and\n100 percent of the direct incident consequences. If 50 percent of the direct incident\nconsequences are avoided, then the benefits of the rule will be $4.0 million over the first\n20 years. If 100 percent of the incident consequences are avoided, then the benefits of\nthe rule will be $8.0 million over the first 20 years.? Thus, it is estimated that the benefits\nresulting from the rule will be between $4.0 million and $8.0 million over the first 20\nyears after the rule is issued. This represents the savings attributable only to reduced\ndirect incident consequences, it should be noted.\"°\nComparison of Benefits and Costs\nAs stated above, the proposed regulatory change is assumed to result in minimal costs.\nBenefits are estimated at between $4.0 million and $8.0 million over the first 20 years\n' The average injury requiring hospitalization is assumed to be a \"Severe injury,\" as defined by the U.S.\ntimes the cost to society of a lost life.\nDepartment of Transportation. The cost to society of a \"Severe injury\" is assumed to be equal to 0.1875\n' 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\n\" In deriving this estimate, the property damage reported in Table 4 was deflated using the Producer Price\nestimate used here is midway between these two values.\nIndex, All Commodities, Base=2004. The source of the price index information used here was U.S.\nwhich can be found at www.bls.gov/ro9/9320.pdf.\nDepartment of Labor, Bureau of Labor Statistics, Producer Price Index, All Commodities, 1982=100,\n1° It might be noted that, if only transmission and gathering line incidents were to be used in this analysis,\n° This is the net present value of avoided direct consequences calculated using a 7 percent discount rate.\nthen the estimated monetized benefits would be between $3.6 million and $7.2 million. If only\nbetween $2.8 million and $5.5 million. These estimates were calculated for the first 20 years after\ntransmission incidents were to be used in this analysis, then the estimated monetized benefits would be\nimplementation of the proposed rule using a 7 percent discount rate.\n9\n\n<<<PAGE 10>>>\n\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\nfollowing implementation of the rule. These benefits focus exclusively on avoided direct\nconsequences of incidents (i.e., deaths, injuries, property damage, and lost product), and\ndo not include other potential benefits, such as avoided economic consequences of\naccident-induced supply restrictions, avoided legal costs, reduced emergency response\ncosts, or increased operational life of pipe.\nFor the rule not to be cost-beneficial, costs would need to be approximately $753\nthousand per year. This would result in total costs in excess of the $8.0 million upper\nlimit on benefits. They would need to be approximately $377 thousand per year to be in\nexcess of the $4.0 million lower limit on benefits.11\nConclusion\nPHMSA believes that the rule represents the most cost-effective alternative for ensuring\ninternal corrosion control on gas transmission pipelines. Furthermore, PHMSA expects\nthat the rule would have a positive net benefit for pipeline operators, public safety, and\nthe public environment.\n11 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\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\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.12\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 1390 operators. Those operators consist of gas transmission and gathering\nsystems. Of the gas transmission system operators impacted by the rule, none are small\nentities. Some gas gathering system operators may be small entities. The exact number\nof gas gathering system operators that are small business according to the Small Business\nAdministration’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.\n12 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\nF F Fi i in n na a al l l R R Re e eg g gu u ul l la a at t to o or r ry y y E E Ev v va a al l lu u ua a at t ti i io o on n n\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","truncated":false,"body_characters":28014}