U.S. DOT/PHMSA - Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis

Page 1D 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 _______________________________________ Regulatory Assessment with Regulatory Flexibility Analysis Paperwork Reduction Act Analysis Draft Regulatory Evaluation Notice of Proposed Rulemaking--Pipeline Safety: Design and Construction Standards to Reduce Internal Corrosion in Gas Transmission Pipelines [Docket No. PHMSA-2005-22642] October 2005 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 (PHMS0A) U.S. Department of Transportation 1#

Page 2Drait Regulatory Impact Assessment Regulatory Analysis Introduction The Pipeline and Hazardous Materials Safety Administration (PHMSA) is proposing regulations on the control of internal corrosion when designing and constructing new and replaced gas transmission pipelines. The proposed rule would require 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 proposed rule would also require an operator to design and construct pipelines to mitigate the impact of internal corrosion that may occur. These proposed changes would facilitate steps tha operators are already required to take in operating and maintaining their pipelines to prevent or mitigate internal corrosion. Need for the Action Internal corrosion has been one of the three leading causes of reportable incidents in gas transmission pipelines for the past five years, both in terms of percentage of incidents and their consequences (see Tables 1 and 2). In fact, in 2003 and 2004, internal corrosion caused more property damage than the other two most frequent causes, third party excavation damage and external corrosion, combined. Table 1: Percentage of Total Natural Gas Transmission System Incidents for the Three Leading Causes Cause / Year 2000 2001 2002 2003 2004 2005** (% of Total Incidents) External corrosion 18 8 9 12 12 10 Internal corrosion 20 19 Excavation damage 25* 43* 18 21 *In 2000 and 2001, number includes all incidents attributable to outside force damage plus ** 2005 data reported as of 10/14/2005. excavation damage. Source: PHMSA, Incident Reporting Form 7100.2 Data as of 10/14/2005 Table 2: Amount of Property Damage for Gas Transmission System Incidents for the Three Leading Causes (in Millions of Dollars) Cause / Year 2000 2001 2002 2003 2004 2005** (in Million $) External corrosion $3.5 $2.0 $4.1 $8.4 $1.6 $88.7 Internal corrosion $2.6 $3.3 $4.0 $14.9 $4.9 $4.2 Excavation damage $3.2* $14.9* $1.1 $3.5 $2.4 $1.3 2#

Page 3D 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 *In 2000 and 2001, number includes all incidents attributable to outside force damage plus excavation damage where appropriate. ** 2005 data reported as of 10/14/2005. A single incident in 2005 caused $87.5 million in property damage. Source: PHMSA, Incident Reporting Form 7100.2 Data as of 10/14/2005. . 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 be designed and constructed with the need to control internal corrosion in mind. Including such requirements would facilitate corrosion control measures in an operating pipeline. In addition, the National Transportation Safety Board recommended the issuance of Federal design and construction standards for internal corrosion control. 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 proposed 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 proposed 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 proposed rules on small entities. 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. 3#

Page 4D 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 In accordance with the above directives, PHMSA has performed a preliminary evaluation of the potential compliance costs of the proposed 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. This proposed 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 proposed rule would 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. 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 proposed 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 would 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. 4#

Page 5D 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 • 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 would be identified, and then the economic impact of the proposed rule would be considered. Impacted Industries, Including Identification and Characteristics of the Potentially Affected Industries The proposed rule would 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 would 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 proposed rule. Table 3. Salient Characteristics of Natural Gas Transmission Pipelines and Gathering Lines Characteristic Value Number of operators 903 Total natural gas transmission and gathering pipeline mileage 322,836* Estimated onshore annual new and replacement mileage 2,506* Estimated offshore annual new and replacement mileage 325* Total annual new and replacement mileage expected to be impacted by the proposed rule 2,831 *Mileage information submitted by 903 operators in 2004 Annual report submitted in 2005. Source: PHMSA, 2004 Annual reports for gas transmission and gathering systems PHMSA 7100.2-1 The proposed rule would not impact the full 322,836 miles of natural gas transmission and gathering lines. Rather, only new or replaced pipeline would be subject to the proposed rule. To estimate the new and replacement mileage information in Table 3, this analysis used the total mileage of onshore and offshore pipes installed during 2000-2004 from the annual reports and assumed that, on average (total mileage divided by 5 years 2000-2004) operators would continue to add or replace pipes at the same rate in future. For example, total onshore transmission and gathering lines installed during 2000-2004 were reported as 12,530 miles. The analysis assumed that during the period 2000-2004 5#

Page 6D 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 this mileage represents the new or replacement pipes. Therefore, on average 12,530/5 or 2,506 per year is the estimated onshore transmission plus gathering miles that would be subject to the proposed rule. Similarly, 1,624 miles of offshore transmission and gathering lines were installed during this period (2000-2004), therefore, 1,624/5 or 325 miles per year of offshore transmission and gathering lines would be subject to the proposed rule. The total annual estimate is the sum of the onshore and offshore annual estimates of natural gas transmission and gathering miles or (2,506+325) = 2,831 miles of new or replacement pipes per year. Impact of the Proposed Regulations PHMSA’s proposed rule would 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 regulations proposed by PHMSA 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 regulations 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 proposed rule would be any associated with • The design and construction of new and replaced pipeline to control internal corrosion, • 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 • Record keeping. The remainder of this cost section addresses the potential 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 proposed rule would 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 would 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 proposed rule are unknown. They could vary from $0 on up, depending on such things as the nature of the gas that would 3 For an overview of the construction process applicable to transmission pipelines, see primis.phmsa.dot.gov/pipelineInfo/const_overview.htm. 6#

Page 7D 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 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 proposed 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 proposed 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 proposed rule are unknown. Most new or replaced pipeline would be operated and maintained exactly as it would have been in the absence of the proposed 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 proposed rule are expected to be relatively minor (e.g., if the proposed 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 proposed 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 proposed rule requires consideration of the impact on downstream pipeline. It is left up to the operator 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 proposed rule. For the purposes of this analysis, the modification costs attributable to the new rule are assumed to be minimal. Record keeping – The cost of record keeping resulting from the proposed regulation would be nominal, if any. Records relating to pipeline design, construction, operation, and maintenance are already being kept by operators. 49 CFR Part 192 recordkeeping requirements currently apply to all operators transporting natural and other gas by pipeline under PHMSA jurisdiction. Prudent business practice also requires that pipeline operators keep pipeline design and construction records. Those records would be created for design and construction purposes, of course, but could satisfy the requirements of the NPRM with minimum, if any, additional burden to the industry. Additionally, 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. Furthermore, 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” is required. Therefore existing recordkeeping requirements would support additional burdens, if any, of this NPRM. 7#

Page 8D 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 Overall – Overall, it is assumed that the costs attributable to the proposed rule would be minimal. The corrosion control requirements embodied in the proposed 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 proposed rule would 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 would 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. Table 4 presents a summary of the reported internal corrosion incident consequences on natural gas transmission pipelines from 2000 through 2004. Table 4: Summary of Internal Corrosion Incident Consequences on Natural Gas Transmission Pipelines, 2000 to 2004 Year Number of Property Injuries Deaths incidents damage (millions of $) 2000 16 $2.6 2 12 2001 9 $3.3 0 0 2002 15 $4.0 0 0 2003 13 $14.8 0 0 2004 23 $4.9 0 0 Source: PHMSA, ops.dot.gov/stats/stats.htm. 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. 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 over 20 years as a result of reduced economic consequences of accident-induced supply restrictions. 5 Neil G. Thompson, “Appendix E, Gas and Liquid Transmission Pipelines,” estimates that “[l]egal issues and liabilities” add between $100 million and $200 million per fatality and injury to the costs associated with pipeline corrosion incidents. 8#

Page 9D 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 The Department of Transportation currently makes the following assumptions concerning the value of a statistical life and the value of an injury requiring hospitalization: • The value of a statistical life is $3,000,000 • Injuries requiring hospitalization are valued at $562,500.6 In addition, for the purposes of this analysis, the natural gas lost as a result of a reportable incident is assumed to be valued at $431 thousand.7 On average over the period from 2000 through 2004, the direct consequences of internal corrosion incidents on gas transmission pipelines cost $0.06 million per thousand miles per year.8 The proportion of the direct incident consequences that the proposed rule would prevent is unknown. For the purposes of this analysis, it is assumed that the proposed rule would 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 proposed rule would be $7.8 million over the first 20 years. If 100 percent of the incident consequences are avoided, then the benefits of the proposed rule would be $15.7 million over the first 20 years.9 Thus, it is estimated that the benefits resulting from the proposed rule would save between $7.8 million and $15.7 million over the first 20 years after the proposed rule is issued. This represents the savings attributable only to reduced direct incident consequences. Comparison of Benefits and Costs As stated above, the proposed regulatory change is assumed to result in minimal costs. Benefits are estimated at between $7.8 million and $15.7 million over the first 20 years following implementation of the proposed 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. 6 The average injury requiring hospitalization is assumed to be a “Severe injury,” as defined by the U.S. Department of Transportation. The cost to society of a “Severe injury” is assumed to be equal to 0.1875 times the cost to society of a lost life. 7 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 estimate used here is midway between these two values. 8 In deriving this estimate, the property damage reported in Table 4 was the Producer Price Index, All Commodities, Base=2004. The source of the price index information used here was U.S. Department of Labor, Bureau of Labor Statistics, Producer Price Index, All Commodities, 1982=100, which can be found at www.bls.gov/ro9/9320.pdf. 9 This is the net present value of avoided direct consequences calculated using a 7 percent discount rate. 9#

Page 10D 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 For the proposed rule not to be cost-beneficial, costs would need to be in excess of $1.48 million per year. This would result in total costs in excess of the $15.7 million upper limit on benefits. They would need to be approximately $736 thousand per year to be in excess of the $7.8 million lower limit on benefits.10 Conclusion PHMSA believes that the proposed rule represents the most cost-effective alternative for ensuring internal corrosion control on gas transmission pipelines. Furthermore, PHMSA expects that the proposed rule would have a positive net benefit for pipeline operators, public safety, and the public environment. 10 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 11D 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 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.11 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 903 operators. Those operators consist of gas transmission and gathering systems. Of the gas transmission system operators impacted by the proposed 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. 11 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 12D 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 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#

Page 13D 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 13#