# U.S. DOT/PHMSA - Final Rule - Regulatory Impact Analysis - **operation:** document - **citation:** 0900006481a1780f - **title:** U.S. DOT/PHMSA - Final Rule - Regulatory Impact Analysis - **source type:** rulemaking - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** Not available - **effective on:** Not available - **summary:** Regulatory Impact Analysis: Final Rule Pipeline Safety: Responsibility to Conduct Inspections, Type B Gathering Lines Leak Surveys, and other Pipeline Safety Changes PHMSA-2010-0026 Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration (PHMSA) U.S. Department of Transportation February 2015 1 February 2015 Executive Summary This package of regulatory changes addresses errors and inconsistencies in the current regulations, provides additional clarifications, incorporates industry standards, and responds to an NTSB safety recommendation and petitions for rulemaking. Many of the revisions are small changes... - **machine formats:** - **json:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a1780f.json - **markdown:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a1780f.md - **app url:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a1780f - **source url:** https://downloads.regulations.gov/PHMSA-2010-0026-0053/attachment_1.pdf **body:** <<>> Regulatory Impact Analysis: Final Rule Pipeline Safety: Responsibility to Conduct Inspections, Type B Gathering Lines Leak Surveys, and other Pipeline Safety Changes PHMSA-2010-0026 Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration (PHMSA) U.S. Department of Transportation February 2015 1 <<>> February 2015 Executive Summary This package of regulatory changes addresses errors and inconsistencies in the current regulations, provides additional clarifications, incorporates industry standards, and responds to an NTSB safety recommendation and petitions for rulemaking. Many of the revisions are small changes that would not lead to substantial changes in regulatory requirements, operator practices, or overall costs and benefits. Benefit-Cost Analysis Annual compliance costs are estimated to be $0.55 million. Annual safety benefits are not as easily quantifiable, but are estimated at $25,222 in avoided incident costs, plus many intangible benefits from the improved clarity and consistency of regulations and better information for PHMSA on potential safety issues. Although the quantifiable benefits do not exceed the estimated costs, PHMSA believes that the many non-quantifiable benefits of these changes significantly outweigh the cost of compliance. Regulatory Flexibility Act Analysis The Regulatory Flexibility Analysis found that the rule could affect a substantial number of small entities because of the market structure of the gas and hazardous liquids pipeline industry, which includes many small entities. However, these impacts would not be significant. Unfunded Mandates Act Analysis PHMSA determined that the rule would not impose annual expenditures on State, local, or tribal governments of the private sector in excess of $153 million, and thus does not require an Unfunded Mandates Act analysis.1 1 The Unfunded Mandates Act threshold was $100 million in 1995. Using the non-seasonally adjusted CPI-U (Index series CUUR0000SA0), that number is $153 million in 2013 dollars. 2 <<>> February 2015 1 Introduction The Pipeline and Hazardous Materials Safety Administration (PHMSA) is proposing a package of changes to the pipeline safety regulations. The changes would correct errors, address inconsistencies, and respond to rulemaking petitions. Requirements in several subject matter areas would be affected, including clarifying the responsibility to conduct construction inspections, the performance of leak surveys for Type B gathering lines, qualification requirements for plastic pipe joiners, modifying mill hydrostatic tests for pipe to operate at alternative maximum allowable operation pressure (MAOP), regulating the transportation of ethanol by pipeline, the transportation of pipe, offshore pipeline condition reports, calculating pressure reductions for hazardous liquid pipeline integrity anomalies, testing components other than pipe installed in low- pressure gas pipelines, alternative MAOP Notifications, codifying the National Pipeline Mapping System (NPMS), including welding operators as qualified to use welding equipment, explaining test requirements for components fabricated by welding, and editorial changes. This report analyzes the benefits and costs of the regulatory changes as required by Section 1 of Executive Order 12866 (as amended by E.O.’s 13258 (2002), 13422 (2007), and 13497 (2009)) and Section 1 of E.O. 13563 (2011). 2 Executive Orders 12866 and 13563 require agencies to regulate in the “most cost-effective manner,” make a “reasoned determination that the benefits of the intended regulation justify its costs,” and develop regulations that “impose the least burden on society.” Analysis of the potential impacts on small entities is also required by the Regulatory Flexibility Act. The Regulatory Flexibility Act analysis is also included in this document (see Section 8). 2 Background PHMSA, pipeline operators, and others have identified certain errors, inconsistencies, updates to standards incorporated by reference, and other deficiencies in the Pipeline Safety Regulations. As such, PHMSA is proposing to make a set of miscellaneous changes to the Pipeline Safety regulations concerning the following subjects, which are described in more detail in sections 3.1 to 3.12 below: • Responsibility to Conduct Construction Inspections • Leak Surveys for Type B Gathering Lines 2 The text of E.O. 12866 can be found here: http://www.archives.gov/federal-register/executive- orders/pdf/12866.pdf and E. O. 13563 here: http://www.whitehouse.gov/sites/default/files/omb/inforeg/eo12866/eo13563_01182011.pdf 3 <<>> February 2015 • Qualifying Plastic Pipe Joiners • Mill Hydrostatic Tests for Pipe to Operate at Alternative Maximum Allowable Operation Pressure (MAOP) • Regulating the Transportation of Ethanol by Pipeline • Transportation of Pipe • Offshore Pipeline Condition Reports • Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies • Testing Components Other than Pipe Installed in Low- Pressure Gas Pipelines • Alternative MAOP Notifications • National Pipeline Mapping System (NPMS) • Welders vs. Welding Operators • Components Fabricated by Welding • Editorial Amendments 3 Identification of the Problem and the Need for the Rule Under the Federal Pipeline Safety Laws, 49 U.S.C. 60101 et seq., the Secretary of Transportation must prescribe minimum safety standards for pipeline transportation and for pipeline facilities. The Secretary has delegated this authority to the PHMSA Administrator (49 CFR 1.53(a)). The rule would create changes in the regulations consistent with the protection of persons and property while changing unduly burdensome or nonsensical requirements. Executive Order 12866 states that "Federal agencies should promulgate only such regulations as are required by law, are necessary to interpret the law, or are made necessary by compelling need, such as material failures of private markets to protect or improve the health and safety of the public, the environment, or the well-being of the American people ... ." The mission of the PHMSA is to ensure the safety of the natural gas and hazardous liquids pipeline system. Pipeline operators do not always bear the full costs of an incident. Even in cases where they provide compensation for losses that can be monetized, those monetary penalties or settlements do not necessarily capture the full impact on affected parties, especially when a death or injury occurs. As a result, there is a negative externality present in which the company may not take the full societal cost of a possible incident into account in its decision-making. The negative externality alters the company’s decision about safety precautions, leading to a need for government to set minimum levels of safety precautions. Pipeline safety regulations are designed to address this potential market failure. The rulemaking package analyzed here is more specifically intended to improve compliance with these regulations by updating references and technical standards, providing clarification, and removing conflicting language. Some of the provisions also promote improved pipeline integrity and safety by addressing small gaps in the current regulations, as discussed in more detail below. 4 <<>> February 2015 Executive Orders 12866 and 13563 direct all Federal agencies to consider the costs and benefits of “significant regulatory actions.” Federal agencies are directed to develop a formal Regulatory Impact Analysis consistent with Office of Management and Budget (OMB) Circular A-4 for all “economically significant” rules, or those rules estimated to have an impact of $100 million in 1995 dollars or more in any one year. The Order also requires a determination as to whether a rule could adversely affect the economy in terms of productivity and employment, the environment, public health, safety, or State, local, or tribal governments. This requirement applies to rulemakings that rescind or modify existing rules as well as to those that establish new requirements. The goal of the analysis is to provide decision makers with a clear indication of the most efficient alternative – that is, the alternative that generates the largest net benefits to society ignoring distributional effects. This rule has been considered a significant regulatory action under Section 3(f) of Executive Order 12866 (58 FR 51735), and therefore is reviewed by OMB. This rule is significant under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034). This rule falls below the $100 million per year in annual impact threshold. This regulatory analysis: • Identifies the target problem, including a statement of the need for the action. • Identifies available alternative approaches • Defines the baseline. • Defines the scope and parameters of the analysis. • Defines and evaluates the costs and benefits of the action and the main alternatives identified by the analysis. • Compares the costs and benefits. • Interprets the cost and benefit results. Subsections 3.1 to 3.12 describe the regulatory changes in detail and the specific needs to which each regulatory change responds. 3.1 Responsibility to Conduct Construction Inspections This rulemaking action would amend the Federal pipeline safety regulations §192.305 and §195.204. The amendments would specify that a transmission pipeline or main cannot be inspected by someone who performed the construction task requiring inspection. Currently, PHMSA does not explicitly state that those who perform a construction task cannot inspect their own work. The National Association of Pipeline Safety Representatives (NAPSR) recommended that contractors who install a transmission line or main should not be allowed to inspect their own work based on their experiences with poor quality construction by unsupervised contractors. Agreeing with NAPSR, PHMSA adopted the rule and took it a step 5 <<>> February 2015 further. PHMSA extended the prohibition to include non-contractor pipeline personnel and hazardous liquid lines. . PHMSA is not requiring that operators hire a third party to perform inspections and revised the language to clarify who is excluded from the inspections. Taking into consideration discussions with the Technical Advisory Committees (TACs), PHMSA adopted language that explicitly identified the individual who performed the construction task as prohibited from carrying out the required inspection. 3.2 Leak Surveys for Type B Gathering Lines This rulemaking action would amend the Federal pipeline safety regulation §192.9 to include the performance of leak surveys for Type B gathering lines by operators and to repair any leaks discovered. Gathering lines are pipelines or parts of a connected series of pipelines that are used to transport gas from a production facility to the first processing plant. Type B is a risk category for lower pressure lines with a MAOP hoop stress of less than 20 percent SMYS (specified minimum yield strength). 3 Currently, operators of onshore Type B gathering line have to comply with other design, installation, construction, and initial testing requirements for transmission lines, and corrosion control requirements if of metallic construction. Additionally, operators already must include Type B gathering lines in their damage prevention and public education programs, establish a MAOP following §192.619, and adhere to requirements for maintaining and installing line markers that apply to transmission lines. In September 2006, NAPSR passed a resolution requesting regulatory change to Type B lines. More specifically, the Supplemental Notice of Proposed Rule Making (SNPRM) [Docket No. RSPA-1998-4868; Notice 5] and the Final Rule for gathering lines [Federal Register; March 15, 2006 (Volume 71, Number 50)] both identified the need to include leak surveys as a compliance activity for Type B gathering lines. It was not incorporated in the Final Rule as it went beyond the scope of the SNPRM and PHMSA did not want to further postpone the rulemaking. Annual leak surveys are a common but not universal practice on Type B gathering lines. In calendar year 2011, the annual Type B report data showed there were 289 leaks eliminated or repaired by operators, with the leading cause of leaks being external corrosion. Ensuring that all operators perform regular leak surveys will help to detect additional gas leaks from pipelines operating under low pressures in a timely manner. 3 PHMA’s definition of gathering lines can be found here: https://www.federalregister.gov/articles/2005/10/03/05-19455/gas-gathering-line-definition-alternative- definition-for-onshore-lines-and-proposed-safety-standards#h-14 6 <<>> February 2015 3.3 Qualifying Plastic Pipe Joiners This rulemaking action would amend the Federal pipeline safety regulation §192.285(c) to provide greater scheduling flexibility and stricter standards for re-qualification of persons who make joints in plastic pipes. Under the current §192.285(c) rule, a joiner must be re-qualified for a certain procedure if the person did not perform that particular joint procedure or has three joints or three percent of joints, whichever is greater, found unacceptable within a 12-month time period. This amendment will extend the 12-month time period to 15 months and reduce the number of unacceptable joints to just one. If any production joint is found unacceptable, a joiner is required to re-qualify. NAPSR in its petition (2008-03-AC-1) noted that the current rule setting a 12-month time period was restrictive and caused the date to constantly be pushed to an earlier date each year. Additionally, NAPSR noted there are a large number of operators requesting waivers similar to NAPSR stating current regulations set too low of standards for joiner re-qualification. 3.4 Mill Hydrostatic Tests for Pipe to Operate at Alternative Maximum Allowable Operating Pressure (MAOP) This rulemaking action would amend the Federal pipeline safety regulation §192.112 by disallowing the combining of loading stresses imposed by pipe mill hydrostatic testing equipment for the mill test. Eliminating the allowance of combining equipment loading stresses will increase the internal test pressure for mill hydrostatic tests for new pipe to be operated at an alternative MAOP. The MAOP refers to the wall strength of a pipe. This requirement ensures new pipes will receive a mill test at a more accurate pressure level of at least 95 percent SMYS and therefore pipes will be more correctly labeled before being put into operation. A hydrostatic mill test requires placing the pipe in a device that uses water to simulate pressure levels. The current rule allows combining the loading stress exerted naturally by the mill test device as a part of the total pressure applied to the pipe. However, this leads to inaccuracies and potential mischaracterization of the actual strength of the pipe. PHMSA identified a number of cases throughout 2008 to 2010 where pipe did not meet the regulatory strength standards. On May 21, 2009 PHMSA issued Advisory Bulletin “Pipeline Safety: Potential Low and Variable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line Pipe.” In this bulletin, PHMSA warned owners and operators of natural gas and hazardous liquid pipeline systems that some pipe joints were found to have as much as 15 percent lower strength than the values advertised by the pipe manufacturer. Following this statement, the Interstate 7 <<>> February 2015 Natural Gas Association of America (INGAA) conducted a study that suggested this change to the testing calculation procedure as one way to prevent operators from putting mislabeled pipe into the ground.4 This change would affect the minority of operators who function under 80 percent SMYS. 3.5 Regulating the Transportation of Ethanol by Pipeline This rulemaking action would amend the Federal pipeline safety regulation §195.2 to add ethanol to PHMSA’s definition of “hazardous liquid.” Presently, a hazardous liquid is defined as petroleum, petroleum products, or anhydrous ammonia. This definition would be expanded to include ethanol. With increasing demand for ethanol, pipelines will be utilized more to transport it and therefore the necessary precautions must be taken. A previous statement published in the Federal Register (72 FR 45002, Docket Number: PHMSA-2007-28136) on August 10, 2007 identified that ethanol “may pose unreasonable risk to life or property,” according to the meaning found in 49 USC 60101(a) (4) (B), and therefore ethanol, ethanol blends, and other biofuels constitute “hazardous liquids for purposes of the pipeline safety laws and regulations. ” From this statement, the few ethanol pipeline operators that exist have already adopted hazardous liquid safety and reporting standards for the biofuel. 3.6 Transportation of Pipe This rulemaking action would amend the Federal pipeline safety regulation §192.65 to remove the exemption of pipe transported before November 12, 1970, to adhere to API’s Recommended Practices 5L1. The current rule states that operators may not install pipe with a hoop stress equal to or greater than 20 percent and an outer diameter to wall thickness of 70 to 1 or more transported by rail, unless it obeys API’s Recommended Practices 5L1 or the pipe was transported prior to November 12, 1970. This exemption existed because the transportation of pipe stockpiled prior to that date cannot be verified under API standards. This exception has now become almost obsolete. The Interstate Natural Gas Association of America (INGAA) conducted surveys and found no pipe made transported before November 12, 1970. NAPSR agreed that there is likely minimal stock of this vintage pipe. However, in the unlikely case that there is still vintage pipe, operators should not be allowed to use it. As seen in the Enbridge pipeline incident on July 4, 2002 and as recommended by the 4 The INGAA Foundation, “White Paper: Identification of Pipe with Low and Variable Mechanical Properties in High Strength, Low Alloy Steels,” September 2009. 8 <<>> February 2015 National Transportation Safety Board (NTSB) report on the incident, all pipe transported by rail should be subject to API’s Recommended Practice 5L1.5 3.7 Offshore Pipeline Condition Reports This rulemaking action would repeal the Federal pipeline safety regulations §191.27 and §195.57 that require operators to submit a report to PHMSA within 60 days of completing the underwater inspections of pipelines in the Gulf of Mexico required by §§ 192.612(a) and 195.413(a). Sections 192.612(a) and 195.413(a) no longer require operators to perform underwater inspections of all pipelines in the Gulf, but rather only necessitate periodic, risk-based inspections of shallow-water pipelines. With the elimination of the underwater inspections, a 60- day reporting period becomes inconsistent with current regulations and therefore PHMSA recommends their repeal. 3.8 Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies This rulemaking action would amend the Federal pipeline safety regulation §195.452(h)(4)(i) to include an alternative method for calculating a pressure reduction for immediate repair conditions caused by issues other than corrosion. Currently, an operator of a hazardous liquid pipeline must immediately repair the pipeline by reducing the operating pressure as determined by a formula provided in §451.6.2.2(b) of ASME/ANSI B31.4. There are many threats that can cause an immediate repair condition, yet the formula provided focuses only on corrosion and limits the scope of the rule. On July 17, 2007, PHMSA’s Final Rule attempted to amend §195.452(h)(4)(i); however it was unable to be incorporated due to inaccurate amendatory instructions. This amendment corrected those issues. The new proposal considers the language suggested by the TACs and now states that to calculate the reduction in pressure, the operator must reference 195.452(h)(4)(i)(B) or if that formula does not apply, a 20 percent or greater reduction from the actual operating pressure should be implemented until repairs are complete. 3.9 Testing Components other than Pipe Installed in Low- Pressure Gas Pipelines This rulemaking action would repeal the Federal pipeline safety regulation paragraph §192.505(d) that exempts certain components from post-installation strength test requirements in 5 The Enbridge pipeline incident released approximately 6,000 barrels of crude oil due to fatigue cracks in the pipe in Cohasset, Minnesota. The NTSB report can be found here: http://www.ntsb.gov/doclib/reports/2004/PAR0401.pdf 9 <<>> February 2015 Subpart J of Part 152 and add that provision to §192.503, which imposes general rules applicable to testing all gas pipelines. The GPTC wrote a letter dated March 25, 2010, petitioning PHMSA to repeal and add that provision to the sections stated above. 3.10 Alternative MAOP Notifications This rulemaking action would amend the Federal pipeline safety regulation §192.620(c)(1) to require operators to give 60 days’ notice prior to the start of pipe manufacturing or construction activities of new alternative MAOP pipelines. Under current regulations, operators are required to give 180 days’ notice to each PHMSA pipeline safety regional office where the pipeline is in service before using a new alternative MAOP on any segment. The change will be less restrictive for operators by shortening the notice days to 60. The 60 days’ notice will not delay project activities for operators, while still allowing PHMSA enough forewarning to schedule personnel for safety inspections. 3.11 National Pipeline Mapping System (NPMS) This rulemaking action would amend the Federal pipeline safety regulation §191.29 and §195.61 to implement the statutory requirement for the submission of NPMS data. PHMSA collects NPMS data annually since 2002 as outlined in Section 15 of the Pipeline Safety Improvement Act. 6 Operators are required to submit geospatial, attribute, and metadata as well as public contact information and a transmittal letter. This rulemaking does not change the submission timeline or any requirements. 3.12 Welders vs. Welding Operators This rulemaking action would amend the Federal pipeline safety regulations §192.225, §192.227, §192.229, §195.214, §195.222 to include welding operators as qualified personnel of mechanized and automated welding equipment by adding Section 9 and Appendix A of API 1104 as qualification references. In the current regulation, welders are qualified under Section 6 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code. In expanding the qualification references and including welding operators, PHMSA is ensuring knowledgeable personnel. 6 https://www.npms.phmsa.dot.gov/Documents/Pipeline%20Safety%20Improvement%20Act%202002.pdf 10 <<>> February 2015 3.13 Components Fabricated by Welding This action would amend the Federal pipeline safety regulation §192.153 to clarify the design and test requirements for pressure vessels in meter stations, compressor stations, and other locations that are tested to Class 3 requirements to meet the 49 CFR Part 192 requirements and are tested at 1.5 times the MAOP. Presently, the rule does not explicitly state the testing requirements, but rather refers to them obliquely. This recommendation serves to clearly specify the requirements. Confusion arose from the ASME BPVC Section VIII test pressure standard of 1.3 times the MAOP. However, this test factor does not apply to non- specially ordered compressors or meter stations, or Class 3 or Class 4 locations and therefore is not in compliance with PHMSA regulations. 3.14 Editorial Amendments In this NPRM, PHMSA is also making the following editorial amendments to the Federal pipeline safety regulations: In §195.571, the NACE Standard on Cathodic Protection is now Incorporated by Reference. In the §195.3(c) table indicating publications incorporated by reference, ANSI/API Recommended Practice 651 is corrected to show the right source and reference material §195.565 and §195.573(d). In §195.2, the definition of “Alarm” is amended to include the codification of the new control room management regulations (74 FR 63310). In §192.925(b) and (b)(2), “indirect examination” is replaced with “indirect inspection” for consistency with §192.925(a) and the relating NACE standard. In §195.428(c), “§5.1.2” is revised to “§7.1.2” to correctly reference overfill protection requirements for above ground tanks in the 2010 edition of API Standard 2510. In §192.3, the definition of “Welder” and “Welding Operator” is added. 4 Identification of Available Alternative Approaches 4.1 No Action This was used as the baseline against which PHMSA compared all other alternatives. Regulatory analyses typically consider an alternative in which the agency would not take any action, because it would maintain the status quo. No new requirements would be levied. No costs would be incurred to implement new requirements. No new benefits would result. 11 <<>> February 2015 PHMSA has an obligation to ensure the safe and effective transportation of hazardous liquids and gases by pipeline. The changes in this rulemaking serve that purpose by clarifying the pipeline safety regulations, eliminating conflicting provisions, responding to new statutory mandates, and eliminating unduly burdensome requirements. A failure to undertake these actions would allow for the continued imposition of unnecessary compliance costs without increasing public safety. Accordingly, PHMSA rejected the “no action” alternative. 4.2 Revisions This alternative was determined by PHMSA as the preferred regulatory option and is compared in the document with the baseline “no action” alternative. PHMSA is proposing to make certain amendments, corrections, and editorial changes to the pipeline safety regulations. These revisions would eliminate inconsistencies and respond to several petitions for rulemaking and recommendations from our stakeholders, thereby facilitating the safe and effective transportation of hazardous liquids and gases by pipeline. The changes in this rulemaking serve that purpose by clarifying the pipeline safety regulations and eliminating unduly burdensome requirements. 5 Industry Information The affected industry comprises owners and operators of regulated natural gas and hazardous liquid pipelines. These include a mix of large and small businesses, as well as publically owned utilities, municipalities, and other organizations. Using a combination of PHMSA 2011 Annual Report data and the Dun and Bradstreet company database, there are approximately 3,000 regulated entities when all corporate subsidiaries are separately counted, with a total of 150,000 onsite employees. There are wide variations across entities with respect to the share of employees actually engaged in pipeline operations, especially for public agencies. Among these entities, common industry (NAICS) codes are 211111, Crude Petroleum and Natural Gas Extraction; 221210, Natural Gas Distribution; 324110, Petroleum Refineries; 486910, Pipeline Transportation of Refined Petroleum Products; 486210, Pipeline Transportation of Natural Gas; and 424720, Petroleum and Petroleum Products Merchant Wholesalers. Many of the specific provisions in this rulemaking would apply only to specific subsets of this population, such as operators of gas gathering lines, as described in more detail in Section 6 below. 12 <<>> February 2015 6 Definition and Evaluation of the Benefits and Costs 6.1 Data Sources and Limitations Cost information is taken from PHMSA databases and external datasets as detailed more specifically below. In many cases the changes are so small as to entail little to no quantifiable costs. 6.2 Costs In the sub-sections below, each provision of the rulemaking is analyzed individually for potential cost implications. 6.2.1 Responsibility to Conduct Construction Inspections Construction safety inspections are integral to ensuring the transmission line or main is correctly built and assembled to minimize future hazards. With this provision, PHMSA is not requiring operating companies to hire a third party to perform the inspections, only clarifying that the same employee who conducted the work cannot also inspect it. Inspections can be performed with other employees, but that employee must not have performed the task under inspection. Compliance costs for this provision are minimal, as it clarifies the existing inspection requirement. 6.2.2 Leak Surveys for Type B Gathering Lines This section requires operators of Type B gathering lines to perform annual leak surveys for more rapid detection of external corrosion. PHMSA performed a cost analysis by averaging the daily rate of two leak survey service providers. The average daily cost of surveying two miles of pipeline per day equaled $600. Averaging 2010, 2011, and 2012 miles of Type B gathering lines provided an estimation of how many miles would need to be inspected annually. Approximately 3,650 miles of Type B gathering lines will be required to be inspected annually. Multiplying that by the average cost of $300 per mile (i.e. $600 per 2 miles), the upper bound of total annual expenditure is approximately $1.1 million. Leak surveys, while not currently required for Type B gathering lines, are a widespread industry practice because they serve a business purpose in helping to detect leaks, thereby reducing lost gas and liability exposure. Although operators do not submit data on the extent of these surveys, PHMSA believes that approximately half of all Type B gathering line mileage that would otherwise be affected by this proposal is already being inspected. Therefore, a more realistic estimate of the actual incremental cost is approximately 50% of the upper bound of $1.1 million, or $0.55 million per year. 13 <<>> February 2015 6.2.3 Qualifying Plastic Pipe Joiners PHMSA’s proposal to extend the recertification period from 12 months to 15 months will result in a small cost savings for the affected group of joiners, since their requalification will come up slightly less frequently. At the same time, a small number of joiners will require requalification more often because of the proposal to reduce the standard on unacceptable joints from three joints or three percent, whichever is greater, to just one joint. On balance, the overall cost implications will be minimal, and the overall impact will be a cost savings for the majority of joiners. 6.2.4 Mill Hydrostatic Tests for Pipe to Operate at Alternative Maximum Allowable Operation Pressure (MAOP) This is a technical correction to a testing procedure to ensure that pipe can actually withstand the operating pressure at which it is rated. The removal of the allowance for equipment loading stresses is a change to the estimation formula and does not require new equipment or techniques. Of the small group of manufacturers who produce pipe intended for operation at 80 percent SMYS, many already test up to the 100 percent level, so this rulemaking will affect few facilities. As this change is a technical correction to improve the accuracy of the labeled SMYS, there are no significant costs. 6.2.5 Regulating the Transportation of Ethanol by Pipeline The few ethanol pipeline operators in existence already handle and report as if ethanol were a hazardous liquid due to a PHMSA policy statement from August 10, 2007 identifying the risks involved in ethanol transportation. The increasing demand and expansion of ethanol transported by pipe may pose significant future costs and revenue to the industry, yet this rulemaking does not affect that. As a codification of an existing policy requirement, this section does not entail any significant changes in compliance costs. 6.2.6 Transportation of Pipe As studies performed by PHMSA and INGAA noted, there is relatively little, if any, vintage pipe in stock. Vintage pipe refers to pipe transported prior to November 12, 1970. The exception for allowing the installation of vintage pipe not transported under API’s Recommended Practices 5L1 is outdated and therefore this rule serves primarily as a reporting clarification and updating of regulations. There are no expected cost impacts. 6.2.7 Offshore Pipeline Condition Reports Under this revision, operators no longer are required to provide a report 60 days after an underwater pipeline inspection in the Gulf of Mexico. This editorial clarification maintains 14 <<>> February 2015 consistency with other rules that are no longer observed. This section entails no net societal costs or benefits. 6.2.8 Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies This rule was already addressed in a previous rulemaking from July 17, 2007. With the amendatory instructions corrected, this minor addition to calculating pressure reductions for a pipe under immediate repair conditions will not result in any significant changes in compliance costs. 6.2.9 Testing Components other than Pipe Installed in Low- Pressure Gas Pipelines In moving section 192.505 (d) to section 192.503, all post-installation strength test requirements are located in the same place within the regulations. As no requirements are changing, this rulemaking does not have any incremental compliance costs. 6.2.10 Alternative MAOP Notifications This rulemaking allows for a less restrictive notice period for operators who want to begin manufacturing or construction activities with pipe of a new alternative MAOP: 60 days instead of the current 180 days. As such, it may yield small cost savings and additional flexibility for operators. PHMSA does not anticipate that this change will result in additional costs for the agency. 6.2.11 National Pipeline Mapping System (NPMS) This section simply incorporates existing statute-imposed requirements into the Pipeline Safety Regulations. Since 2002, operators have adhered to the same requirements that will now be codified. There are no anticipated changes to operator filings or requirements, and accordingly no incremental compliance costs. 6.2.12 Welders vs. Welding Operators The additional qualifications for welders and welding operators under the new rulemaking provide no more than a clarification of qualification references allowed by PHMSA. While this will ensure qualified personnel are performing welding activities, it does not result in substantial costs or benefits as the qualification was already outlined in API 1104 Section 9 and Appendix A. 6.2.13 Components Fabricated by Welding Although comments expressed concern over additional costs for operators, this rule is a clarification of an existing rule found in 49 CFR §192.153(e) and distinguishes it from the other ASME BPVC Section VIII ruling. The industry should already follow this requirement, even if 15 <<>> February 2015 it may have been misunderstood by some operators. This clarification of compliance does not incur any new costs to operators as 1.5 times MAOP is an industry standard already adopted by PHMSA. 6.2.14 Editorial Amendments The editorial adjustments correct errors, uphold consistency, and fix small discrepancies throughout the Final Rule. There are no substantive changes to the requirements and therefore no supplementary compliance costs. 6.2.15 Cost Summary In general, many of these amendments are minor rulemakings with little or no substantive changes to industry standards or compliance costs. Only one provision came with major quantifiable costs and this is estimated at $0.6 to million per year for additional operators to perform leak surveys for Type B gathering lines. 6.3 Benefits Pipeline incidents can result in death, injury, property damage, and environmental damage. The benefits of the regulatory changes stem primarily from improvements to regulatory clarity and from upgraded safety requirements that are intended to reduce the number of pipeline incidents and their severity. Estimates of avoided incident costs are calculated using information on fatalities, injuries, and property damage (including lost product). Fatalities and injuries are converted to dollar terms using values from departmental guidance documents, $9.1 million per fatality and $955,500 for an injury.7 [Based on departmental guidance, the injury and fatality figures rise 1.07% per year to account for wage increases over time.] In the sub-sections below, the expected benefits of each provision of the rulemaking are analyzed individually. 6.3.1 Responsibility to Conduct Construction Inspections This section is a clarification explicitly prohibiting the person(s) who performed a construction task from inspecting their own work. Although this was already a widespread industry standard, there may be some incremental safety benefits from formalizing this requirement. 7 Trottenberg, Polly and Robert Rivkin. “Guidance on Treatment of the Economic Value of a Statistical Life (VSL) in U.S. Department of Transportation Analyses.” February 28, 2013. The injury number is equivalent to a “serious” injury on the Abbreviated Injury Scale and is 10.5% of the VSL. 16 <<>> February 2015 Between 1993 and 2012 there were 25 construction, installation, and fabrication- related incidents that resulted in $16,681,026 in reported property damage from gas transmission lines plus 47 incidents from hazardous liquid transmission causing $9,192,653 in property damage. 8 The proportion attributable to errors caused by self-inspection is unknown, so benefits cannot be quantified for this provision. However, PHMSA believes that this explicit inspection rule will improve safety by ensuring unbiased inspections. 6.3.2 Leak Surveys for Type B Gathering Lines By performing leak surveys annually, operators are more likely to detect leaks early, thereby avoiding costlier future repairs and reducing the amount of gas lost. As mentioned in section 3.2, during calendar year 2011, there were 289 reported leaks on Type B gathering lines eliminated or repaired, with the lead cause of these leaks being external corrosion. Leak surveys are particularly important for low pressure gas gathering lines because these lines tend to leak rather than rupture. In addition to the direct operational benefits, annual leak surveys will also reduce the environmental harm caused by lost gas (i.e., the greenhouse gas potential of methane released into the atmosphere). According to PHMSA incident data collected from 1993 to 2012, external corrosion in gas gathering lines caused $2,277,870 in property damage and resulted in one injury.9 Other types of incidents, such as certain equipment failures and punctures, are also potentially preventable through leak surveys. Prior to 2010, the data unfortunately does not distinguish between Type A and Type B gathering lines. For the more limited period from 2010 to 2012, PHMSA incident data includes one incident with an onshore type B gathering line that incurred $76,567 of property damage. This represents an annual average of $25,222 in safety benefits from incidents on Type B gathering lines that are potentially preventable via annual leak surveys. There are also environmental and climate-change benefits from reducing lost gas, but these could not be quantified because of limited data on the quantity of gas lost in the relevant incidents. In addition, these surveys would future cost savings for operators in terms of avoiding more costly repairs. Operator leak reporting also gives PHMSA valuable information that can be used in trending analysis for the determination of problem materials or poor operating practices. These important benefits cannot be quantified. 8 http://primis.phmsa.dot.gov - **truncated:** true - **body characters:** 53113