Rulemakingcurrent
0900006480e93bef
U.S. DOT/PHMSA - Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas Transmission Pipelines - Final Regulatory Evaluation
Current as of source date
RegulusPipeline researchRegulusPipeline research0900006480e93bef
Page 1F 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 Transmission Pipelines [Docket No. PHMSA-2005-22642] March 2007 Prepared by Economic and Industry Analysis Division Volpe National Transportation Systems Center Research and Innovative Technology Administration (RITA) and Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration (PHMSA) U.S. Department of Transportation 1#
Page 2F 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 Analysis Introduction The Pipeline and Hazardous Materials Safety Administration (PHMSA) is adopting regulations on the control of internal corrosion when designing and constructing new and replaced gas transmission pipelines. The rule requires an operator to consider the potential for accumulating liquids that could result in internal corrosion and to take steps in design and construction that would reduce the risk. The rule also requires an operator to design and construct pipelines to mitigate the impacts of internal corrosion that may occur. These changes facilitate steps that operators are already required to take in operating and maintaining their pipelines to prevent or mitigate internal corrosion. Need for the Action In 2003, the National Transportation Safety Board (NTSB) recommended the issuance of Federal design and construction standards for internal corrosion control (see NTSB recommendation P-03-1). The NTSB recommendation arose out of its investigation of the August 19, 2000 gas transmission pipeline incident near Carlsbad, New Mexico. The NTSB concluded that the immediate cause of the Carlsbad incident was a pipeline failure caused by severe internal corrosion. The NTSB issued a final report, recommending (1) rulemaking to require that new and replaced gas transmission pipelines be designed and constructed with features to mitigate internal corrosion; (2) development of requirements for gas operators to address the role of water in their internal corrosion control programs; and (3) changes to Federal inspection to ensure adequate assessments of pipeline operator safety programs. PHMSA has already completed action on the second and third recommendations. This rule completes action on the first recommendation. A variety of options exist for the control of internal corrosion. Those options include controlling the quality of the gas in the pipeline, inspecting the inside of pipe visually, using ultrasound to ascertain pipe wall thickness, using drips to remove liquids in the gas stream, using “slam valves” to cut off the flow of gas when high levels of contaminants are detected, and using alarms to warn when high levels of contaminants are detected.1 To be effective, any drips would need to be drained periodically. A complete internal control program might use a mix of these options, supplemented and complemented by other measures, such as cleaning pigs, inhibitors, internal coatings on pipe, and gas dewatering.2 Currently, pipeline safety regulations found in 49 CFR Part 192 require that operators establish and implement programs to prevent or mitigate internal corrosion in the operation and maintenance of gas transmission pipelines. In addition, the recent integrity management regulations require operators to assess the integrity of their pipelines with respect to internal corrosion. There are no Federal requirements that require pipelines to 1 NTSB Pipeline Accident Report, NTSB/PAR-03/01, pp. 21, 22. 2 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” Cost of Corrosion, FHWA Report FHWA-01-156, April 2005, pp. E-15 to E-16, www.corrosioncost.com/home.html. 2#
Page 3F 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 understandings about the causes and prevention of corrosion. The requirements of this rule improves the ability of the operator to prevent internal corrosion and facilitates maintenance activities to control internal corrosion. Rationale for Regulatory Assessment All proposed and final Federal regulations must undergo economic analysis. Executive Order 12866 directs all Federal agencies to develop both preliminary and final regulatory analyses if their proposed regulations are likely to be “significant regulatory actions” that may have an annual impact on the economy of $100 million. The Order also requires a determination as to whether a rule could adversely affect the economy or a section of the economy in terms of productivity and employment, the environment, public health, safety, or State, local or tribal governments. In accordance with the regulatory philosophy and principles provided in Sections 1(a) and (b) and Section 6(a)(3)(C) of Executive Order 12866, an economic analysis of the regulatory changes must be conducted. Furthermore, the Regulatory Flexibility Act of 1980, as amended, requires Federal agencies to conduct a separate analysis of the economic impact of their rules on small entities. In accordance with the above directives, PHMSA has performed an evaluation of the potential compliance costs of the rule and feasible regulatory options and identified those benefits that can be expressed in monetary terms. To the extent practicable, this is based on the available data and information from a range of pertinent sources. PHMSA estimates that the impact of implementing the rule would be less than $100 million annually, and that the rule would not adversely affect the economy or a section of the economy in terms of productivity and employment, the environment, public health, safety, or State, local or tribal governments. The rule is not considered significant under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034, February 26, 1979). PHMSA has also determined, as required by the Regulatory Flexibility Act, that the rule will not have a significant economic impact on a substantial number of small entities in the United States. Alternatives Considered The goal of this rulemaking is to reduce natural gas transmission system incidents resulting from internal corrosion. In developing the rulemaking, PHMSA considered the following two alternatives: • Do Nothing. • Amend the pipeline safety regulations to add design and construction standards to reduce internal corrosion in gas transmission pipelines. 3#
Page 4F 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 Given the NTSB’s recommendation P-03-1 concerning adding new regulations requiring that new or replaced pipelines be designed and constructed in a manner that would mitigate internal corrosion (see above), and PHMSA’s concurrence with that recommendation, PHMSA believes that it is necessary and appropriate to pursue a Federal rulemaking. Therefore, “Do Nothing” is not viewed by PHMSA as a viable alternative. It is developed no further in this regulatory evaluation. Economic Analysis In its rule, Design and Construction Standards to Reduce Internal Corrosion in Gas Transmission Pipelines, PHMSA is amending 49 CFR Part 192 by adding a new section, § 192.476, mandating that operators consider internal corrosion risk when designing and constructing gas transmission pipelines. The new section will include the following: • Performance tests for design and construction measures to control internal corrosion. • A requirement that an operator consider whether it should install liquid removal equipment or corrosion monitoring devices on existing pipeline downstream of new or replaced pipeline. • A requirement that an operator record the decisions it makes with respect to internal corrosion control when designing and constructing pipelines. In the remainder of this section, the impacted industry is identified, and then the economic impact of the rule will be considered. Impacted Industries, Including Identification and Characteristics of the Potentially Affected Industries The rule will apply to new or replaced pipe and components on all natural gas transmission pipelines whose safety is regulated under 49 CFR Part 192. In addition, the requirements will apply to gathering lines. The operators of natural gas transmission pipelines are generally large firms. The operators of gathering lines are not, however (i.e., some are small entities). The following table shows the salient characteristics of the natural gas transmission pipelines impacted by the rule. Table 3. Salient Characteristics of Natural Gas Transmission Pipelines and Gathering Lines Characteristic Value Number of operators 1390 Total onshore natural gas transmission and gathering pipeline mileage 300,755 Estimated onshore annual new and 2,096* 4#
Page 5F 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 replacement mileage – transmission Estimated onshore annual new and replacement mileage – gathering lines 166* Total annual new and replacement mileage expected to be impacted by the rule 2,262* *Based on mileage information submitted by 1390 pipeline operators in their 2005 annual reports to PHMSA. Source: PHMSA, 2005 Annual reports for gas transmission and gathering systems PHMSA 7100.2-1 The rule will not impact the full 300,755 miles of onshore natural gas transmission and gathering lines estimated to in operation. Rather, only new or replaced pipeline will be subject to the rule. To estimate the new and replacement mileage information in Table 3, this analysis used the total mileage of onshore transmission pipes installed during 2000- 2005 from the annual reports and the total mileage of onshore gathering lines during 2000-2005, and assumed that, on average, operators would continue to add or replace pipes at the same rate in future. Total onshore transmission pipe installed during 2000- 2005 was reported as 12,578 miles, so the average installed each year over the six-year period from 2000 through 2005 was 2,096 (= 12,578 / 6). Total onshore gathering line pipe installed during 2000-2005 was reported as 999 miles, so the average installed each year over the six-year period from 2000 through 2005 was 166 (= 999 / 6). The analysis assumed that these mileages represent onshore new or replacement pipes for transmission and gathering systems, respectively. In total, the estimated additional onshore transmission plus gathering line mileage that would annually become subject to the rule would be 2,262 miles (= 2,096 miles + 166 miles). It should be noted that, with each 2,262 mile increment, more and more pipeline would become subject to the rule over time. Impact of the Rule PHMSA’s new rule will impact the internal corrosion control activities of gas transmission and gathering lines. Those activities make pipeline operations safer by helping to reduce the number of incidents. The rule may result in added costs related to internal corrosion control that would be borne by pipeline operators and added benefits that include a reduction in the number of incidents. The rule should also facilitate future operation and maintenance efforts on the new and replaced lines that have been designed with corrosion in mind. Costs The costs attributable to the rule will be any associated with • The design and construction of new and replaced pipeline to control internal corrosion, 5#
Page 6F 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 • Operation and maintenance activities required due to designing pipeline to control internal corrosion, • Actions taken to modify existing pipeline downstream of and impacted by new or replaced pipeline, and • Recordkeeping. The remainder of this cost section addresses the costs related to pipeline design, construction, downstream modification, and record keeping. Design – The costs attributable to designing new or replaced pipeline to meet the prevention and mitigation requirements of the rule will be nominal. When pipeline operators add or replace pipeline, they already go through a design process, and the design teams include individuals with corrosion expertise. There is no evidence to indicate that mandating the inclusion of internal corrosion prevention and mitigation in the design of a pipeline will materially impact the cost of this process. Construction3 – The costs attributable to constructing new or replaced pipeline that meets the prevention and mitigation requirements of the rule are unknown. They could vary from $0 on up, depending on such things as the nature of the gas that would be transported, the terrain, and control and monitoring devices, if any, that would be used. Most new or replaced pipeline would be constructed exactly as it would have in the absence of the rule, because terrain and operating conditions are similar to adjoining pipeline, and internal corrosion is not a high risk threat for that adjoining pipeline. For pipeline that is constructed differently than it would have been in the absence of the rule, the changes are expected to be relatively minor (e.g., the addition of drips at strategic locations). These relatively minor changes are expected to result in equally minor additions to construction costs. For the purposes of this analysis, the construction costs attributable to the new rule are assumed to be minimal. Operation and Maintenance – The operation and maintenance (O&M) costs attributable to operating new or replaced pipeline that meets the prevention and mitigation requirements of the rule are unknown. Most new or replaced pipeline would be operated and maintained exactly as it would have been in the absence of the rule, because terrain and operating conditions are similar to adjoining pipeline, and internal corrosion is not a high risk threat for that adjoining pipeline. Changes in O&M due to the rule are expected to be relatively minor (e.g., if the rule results in the addition of a drip on a new or replaced line, then an O&M impact would be that the drip would need to be cleaned periodically). The changes in O&M due to the rule are expected to result in relatively minor additional costs. For the purposes of this analysis, O&M costs attributable to the new rule are assumed to be minimal. Downstream Modification – The costs attributable to modifying existing downstream pipeline that may be impacted by new or replaced pipeline are unknown. The rule requires consideration of the impact on downstream pipeline. It is left up to the operator 3 For an overview of the construction process applicable to transmission pipelines, see primis.phmsa.dot.gov/pipelineInfo/const_overview.htm. 6#
Page 7F 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 to decide whether to make any modifications. Presumably, that would be a business- based decision that would have been the same even in the absence of the rule. For the purposes of this analysis, the modification costs attributable to the new rule are assumed to be minimal. Recordkeeping –Records relating to pipeline design, construction, operation, and maintenance are already being kept by operators. Prudent business practice requires that pipeline operators keep pipeline design and construction records. Those records are created for design and construction purposes, of course, but could satisfy the requirements of the rule with minimal, if any, additional burden to the industry. The recordkeeping requirements currently included in 49 CFR Part 192 apply to all operators transporting natural and other gas by pipeline under PHMSA jurisdiction. Those requirements cover at least some of the records that would need to be kept under the proposed regulations. For instance, 49 CFR 192.605(b)(3) requires procedures be established for “[m]aking construction records…available to appropriate operating personnel.” To do this, of course, those construction records must be maintained by operators already. Additionally, 49 CFR 192.491 requires the maintenance of records “…to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist.” Therefore, existing recordkeeping requirements will also help minimize the additional burdens, if any, of the rule. As a consequence of the foregoing, PHMSA expects the costs, if any, associated with the recordkeeping requirements of the proposed regulations to be nominal. Overall – Overall, it is assumed that the costs attributable to the rule will be minimal. The corrosion control requirements embodied in the rule would function primarily as a reminder of the importance of corrosion control, particularly control of corrosion due to liquids. It would heighten the awareness of operators to the problem of internal corrosion. Prudent business practices should already encourage operators to make all reasonable efforts to control internal corrosion. This would prevent accidents, protect the operator’s investment, improve reliability of the line, and reduce future maintenance costs. Benefits The benefits of the rule will include a reduction in the direct consequences of internal corrosion incidents (i.e., a reduction in the deaths, injuries, property damage, and lost product directly attributable to internal corrosion incidents). It will also include other savings, such as those related to making future maintenance easier, increasing the operational life of pipe, and avoiding economic consequences of accident-induced supply restrictions,4 legal costs,5 and reduced emergency response costs. In this analysis, however, only the expected reduction in the direct consequences is estimated. 4 Final Regulatory Evaluation, Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),” Docket RPSA-00-7666, for instance, estimated that, as a result of the Pipeline Integrity Management in High Consequence Areas regulations, approximately $1 billion would be saved 7#
Page 8Fuel Regulatory Evaluation damage are included in the table. Table 4: Summary of Internal Corrosion Incident Consequences on Natural Gas Transmission Pipelines, 2000 through 2005 Year Number of Property Injuries Deaths incidents damage Transmission 2000 5 $1,479,196 0 2001 3 $1,015,850 2002 3 $557,683 2003 3 $6,045,720 2004 2 $149,758 2005 3 $282,034 Gathering 2000 3 $172,000 0 2001 3 $2,000,000 0 2002 1 $45,000 0 2003 1 $127,000 0 2004 1 $600,000 0 2005 2 $718,500 0 0 Compressor Stations 2000 0 2001 0 0 2002 0 0 0 2003 2 $7,363,000 0 0 2004 0 0 2005 0 Total - All Categories 2000 8 $1,651,196 0 0 2001 6 $3,015,850 0 2002 4 $602,683 0 2003 6 $13,535,720 2004 3 $749,758 0 2005 5 $1,000,534 0 0 Source: PHMSA, transmission system incident reports 8#
Page 9Fuel Regulatory Evaluation The values for 2000, it might be noted, include the internal corrosion incident that occurred at Carlsbad, New Mexico, on an El Paso Natural Gas pipeline. the value of a statistical life and the value of an injury requiring hospitalization: The Department of Transportation currently makes the following assumptions concerning • The value of a statistical life is $3,000,000 • Injuries requiring hospitalization are valued at $562,500.° incident is assumed to be valued at $431 thousand.? In addition, for the purposes of this analysis, the natural gas lost as a result of a reportable On average over the six-year period from 2000 through 2005, the direct consequences of internal corrosion incidents on 300,755 miles of onshore transmission and gathering pipelines cost $40 per mile per year.® The proportion of the direct incident consequences that the rule will prevent is unknown. For the purposes of this analysis, it is assumed that the rule will prevent between 50 and 100 percent of the direct incident consequences. If 50 percent of the direct incident consequences are avoided, then the benefits of the rule will be $4.0 million over the first 20 years. If 100 percent of the incident consequences are avoided, then the benefits of the rule will be $8.0 million over the first 20 years.? Thus, it is estimated that the benefits resulting from the rule will be between $4.0 million and $8.0 million over the first 20 years after the rule is issued. This represents the savings attributable only to reduced direct incident consequences, it should be noted."° Comparison of Benefits and Costs As stated above, the proposed regulatory change is assumed to result in minimal costs. Benefits are estimated at between $4.0 million and $8.0 million over the first 20 years ' The average injury requiring hospitalization is assumed to be a "Severe injury," as defined by the U.S. times the cost to society of a lost life. Department of Transportation. The cost to society of a "Severe injury" is assumed to be equal to 0.1875 ' Neil G. Thompson, "Appendix E, Gas and Liquid Transmission Pipelines," estimates that a corrosion incident results in lost product valued at between $287 thousand and $574 thousand. The $431 thousand " In deriving this estimate, the property damage reported in Table 4 was deflated using the Producer Price estimate used here is midway between these two values. Index, All Commodities, Base=2004. The source of the price index information used here was U.S. which can be found at www.bls.gov/ro9/9320.pdf. Department of Labor, Bureau of Labor Statistics, Producer Price Index, All Commodities, 1982=100, 1° It might be noted that, if only transmission and gathering line incidents were to be used in this analysis, ° This is the net present value of avoided direct consequences calculated using a 7 percent discount rate. then the estimated monetized benefits would be between $3.6 million and $7.2 million. If only between $2.8 million and $5.5 million. These estimates were calculated for the first 20 years after transmission incidents were to be used in this analysis, then the estimated monetized benefits would be implementation of the proposed rule using a 7 percent discount rate. 9#
Page 10F 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 following implementation of the rule. These benefits focus exclusively on avoided direct consequences of incidents (i.e., deaths, injuries, property damage, and lost product), and do not include other potential benefits, such as avoided economic consequences of accident-induced supply restrictions, avoided legal costs, reduced emergency response costs, or increased operational life of pipe. For the rule not to be cost-beneficial, costs would need to be approximately $753 thousand per year. This would result in total costs in excess of the $8.0 million upper limit on benefits. They would need to be approximately $377 thousand per year to be in excess of the $4.0 million lower limit on benefits.11 Conclusion PHMSA believes that the rule represents the most cost-effective alternative for ensuring internal corrosion control on gas transmission pipelines. Furthermore, PHMSA expects that the rule would have a positive net benefit for pipeline operators, public safety, and the public environment. 11 For this comparison, it is assumed that all costs are incurred in the year in which new or replaced pipeline is installed. O&M costs, if any, may be incurred in subsequent years, but it is not possible to say what those recurring O&M costs might be. 10#
Page 11F 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 Flexibility Analysis The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires an agency to review regulations to assess their impact on small entities unless the agency determines that a rule is not expected to have a significant impact on a substantial number of small entities. The design and construction standards rule would not have a significant impact on a substantial number of small entities.12 Need for the Final Rule: PHMSA presently has regulations relating to internal corrosion prevention applicable to natural gas transmission pipeline operators. Those regulations are found in 49 CFR 192. PHMSA believes that additional regulations enhancing these existing regulations are necessary to give further guidance to pipeline operators. Description of Actions: In the Notice of Propose Rulemaking, PHMSA is proposing to amend the Federal pipeline safety regulations by requiring operators to consider the control of internal corrosion when designing and constructing new and replaced gas transmission pipelines. Identification of potentially affected small entities: For the purposes of the current analysis, it is assumed that the proposed changes in the regulations would impact an estimated of 1390 operators. Those operators consist of gas transmission and gathering systems. Of the gas transmission system operators impacted by the rule, none are small entities. Some gas gathering system operators may be small entities. The exact number of gas gathering system operators that are small business according to the Small Business Administration’s threshold of $6 million in revenue or 1,500 in employee size is unknown, but it is not substantial. Compliance, reporting, and recordkeeping requirements: This Notice of Proposed Rulemaking includes new compliance requirements. Impacted pipeline operators would be required to consider the potential that accumulating liquids could result in internal corrosion and to take steps during design and construction that would reduce the risk. Prevention and mitigation on the new or replaced pipeline, and the impact of the actions taken on downstream pipeline must all be considered. Operators must document all design and construction decisions relating to the prevention and mitigation of internal corrosion. The costs of these actions are expected to be minimal. Related Federal rules and regulations: Existing rules relating to internal corrosion prevention on gas transmission pipelines can be found in 49 CFR 192. With respect to the safety of the transportation of natural gas by pipeline there are no related rules or regulations issued by other departments or agencies of the Federal Government. 12 As defined by the Small Business Administration, small entities in the pipeline industry, have either fewer than 500 employees or less than $6 million in revenue, depending on the particular NAICS (North American Industry Classification System) industry into which the entity falls. For more information, see www.sba.gov/size/index.html. 11#
Page 12F 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 Alternate proposals for small businesses: The Regulatory Flexibility Act directs agencies to establish exceptions and differing compliance standards for small businesses, where it is possible to do so and still meet the objectives of applicable regulatory statutes. In the case of corrosion prevention, no exceptions for small businesses are proposed. Conclusion: Based on available information, it can be concluded that, this Notice of Proposed Rulemaking does apply to some small entities (i.e., to some gas gathering system operators), but it would not result in a significant economic impact on any small entities. 12#
This material provides agency context. It does not replace binding regulatory text, and its legal effect depends on the underlying authority and facts.