# Final Regulatory Impact Analysis for Pipeline Safety: Integrity Management Program for Gas Pipelines RIN 2137-AE15 - **operation:** document - **citation:** 0900006481a47e78 - **title:** Final Regulatory Impact Analysis for Pipeline Safety: Integrity Management Program for Gas Pipelines RIN 2137-AE15 - **source type:** rulemaking - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** Not available - **effective on:** Not available - **summary:** Material conclusions and scope (quoted exactly): the rule adds a new Subpart P to 49 CFR Part 192 requiring gas distribution Integrity Management plans and EFV installation on new/replaced single-residence service lines (see passages regulations-gov-attachment-0900006481a47e78-node-3, -6, -16). PHMSA estimated the rule's present-value net benefits over 50 years to lie between $21 million and about $1.6 billion (passage node-3). The Agency assessed annual costs at about $130 million in the first year and about $101 million in subsequent years, with estimated annual monetary benefits between $111 million and $165 million (passage node-3). PHMSA estimated approximately 9,090 small entities would be impacted and that 9,343 operators, 1,138,000 miles of distribution mains and 60,970,000 services are affected (passages node-4, node-18, node-19). The RIA describes PHMSA's selection of a risk‑b^ - **machine formats:** - **json:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a47e78.json - **markdown:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a47e78.md - **app url:** https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006481a47e78 - **source url:** https://downloads.regulations.gov/PHMSA-2011-0009-0026/attachment_1.pdf **body:** <<>> Final BEPTOf|/,pRWION 9 -I A p- n ~> . Regulatory Impact Analysis: Final Rule Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines PHMSA-RSPA-2004-19854 Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration (PHMSA) U.S. Department of Transportation October 29,2009 <<>> TABLE OF CONTENTS EXECUTIVE SUMMARY 1 1. INTRODUCTION 3 2. BACKGROUND 7 3. REGULATORY ANALYSIS 8 4. IDENTIFICATION OF THE PROBLEM AND THE NEED FOR THE RULE 8 5. IDENTIFICATION OF AVAILABLE ALTERNATIVE APPROACHES 10 6. INDUSTRY INFORMATION 15 7. DEFINITION AND EVALUATION OF THE BENEFITS AND COSTS 17 8. BREAK-EVEN ANALYSIS 61 9. SUMMARY AND CONCLUSIONS 62 APPENDIX A: SUPPLEMENTARY STATISTICAL VALUE OF LIFE ANALYSIS 64 APPENDIX B: ESTIMATES OF AVERAGE COST PER LIFE SAVED 66 11 <<>> EXECUTIVE SUMMARY The Pipeline and Hazardous Materials Safety Administration (PHMSA) is amending the Federal Pipelme Safety Regulations to require operators of gas distribution pipelines to develop and implement Integrity Management (IM) programs. The purpose of these programs is to enhance safety by identifying and reducing pipeline integrity risks. The rule addresses the statutory mandates and recommendations from the Department of Transportation's (DOT) Office of the Inspector General (OIG) and stakeholder groups. The IM programs required by this rule are similar to those required for gas transmission pipelines but are tailored to reflect the differences in and among distribution pipelines. PHMSA requires operators of gas distribution pipelines to develop and implement IM plans that will better assure the integrity of their pipeline systems. All E M program requirements pertain to distribution operators with the exception of master meter and small liquid petroleum gas (LPG) distribution systems. To minimize regulatory burdens, the rule establishes simpler requkements for master meter and LPG operators serving fewer than 100 customers from a single source, reflecting the relatively lower risk posed by these small pipeline systems. The Regulatory Impact Analysis (RIA) finds that the rule is not expected to adversely affect the economy or the environment. The analysis fmds that, for those costs and benefits that can be quantified, the present value of net benefits is expected to be between $21 million and about $1.6 billion over a 50-year period after all of the requirements are implemented. Furthermore, the net benefits of the rule are expected to be positive if the rule results in eliminatmg only approximately 12.2 percent of the overall societal costs the first year, and about 9.5 percent in subsequent years. PRESENT VALUE OF BENEFITS, COSTS, and NET BENEFITS OF THE RULE CALCULATED OVER 50 YEARS ($ Millions) DiscouiilRate 3% 7% Benefits s 2,942 to 4,373 1,639 to 2,437 CdM 2,783 1,618 Net Benefits 159 to 1,590 21 to 719 The estimated monetary cost of the rule is $130 million in the first year and about $101 million in subsequent years, while the estimated annual monetary benefits are between $111 million and $165 million. DOT has classified this rulemaking as an economically significant regulatory action under Section 3(f)(1) of Executive Order 12866, and a significant regulatory action under the DOT's regulatory policies and procedures (44 FR 11034). There is substantial congressional, industry, and public interest in the rule. PHMSA has also estimated, as required by the Regulatory Flexibility Act (RFA), that the rule would have an impact on many small operators. PHMSA estimates that <<>> approximately 9,090 small entities will be impacted by the rule. PHMSA cannot estimate the percent of revenues the costs of the rule represent for small operators, since the Agency does not have information on their revenues. The rule could result in a significant adverse economic impact for at least some of the small master meter and small LPG systems, if the costs exceed 1 percent of their revenues. A Final Regulatory Flexibility Analysis (FRFA), which discusses these issues has been completed and placed in the docket. PHMSA determined that the rule would not impose annual expenditures on State, local, or tribal governments or the private sector in excess of $141.3 million, and thus does not require an Unfunded Mandates Act analysis. <<>> 1. INTRODUCTION The Pipelme and Hazardous Materials Safety Administration (PHMSA) has issued Integrity Management Program (IM program) regulations for operators of hazardous liquid pipelines (49 CFR 195) and gas transmission pipelines (49 CFR Part 192). Those regulations require operators to continually assess, evaluate, repair, and validate through comprehensive analysis the integrity of pipeline segments, and to take actions to address applicable threats and integrity concerns. Similar regulations do not currently exist for gas distribution pipelines. PHMSA is revising the Pipeline Safety Regulations to require operators of gas distribution pipelines to develop and implement programs that will better assure the integrity of their pipeline systems. PHMSA published a Notice of Proposed Rulemaking (NPRM) on June 25, 2008 (73 FR 36015), which proposed to extend its mtegrity management approach to the largest segment of the Nation's pipeline network—the gas distribution pipelines that directly serve homes, schools, businesses, and other natural gas consumers. Significant differences between distribution pipelines and gas transmission or hazardous liquid pipelines made it impossible simply to apply the existing regulations to distribution pipelines. The proposed rule incorporated the same basic principles as current integrity management regulations but with a slightly different approach to accommodate those differences. Over the period 1989-2008, significant incidents associated with gas distribution pipeline systems result, on average, in more than 15 fatalities, over 62 serious injuries, and tens of millions of dollars of property damages annually.' The purpose of this regulation is to address the hazards that lead to those incidents as well as reduce gas loss by including leak management and excess flow valve (EFV) provisions. This rule addresses recommendations from DOT's Inspector General and the National Transportation Safety Board (NTSB). It also implements requirements in the Pipeline Inspection, Protection, Enforcement and Safety Act (PIPES Act) of 2006. 1.1 Requirements of the Integrity Management Program The requirements for distribution pipeline operators are described below. Gas Distribution Pipeline Integrity Management (DIMP) The final rule revises 49 CFR Part 192 to add integrity management requhements applicable to distribution pipelines. This addresses statutory mandates and builds on previous similar requirements established for gas transmission pipelines. The final rule ' Natural Gas Distribution: Significant Incidents Summary Statistics: 1989-2008, Significant Pipeline Incidents, PHMSA. <<>> also adds a requkement that operators install excess flow valves (EFV) on all new and replaced residential service lines serving single residences, as required by the PIPES Act. The requirements for gas distribution operators and LPG operators with distribution systems serving 100 or more customers from a single source ("large" LPG operators^) are listed under section 1.1.1 below. These are followed by the requirements for master meter operators and small LPG operators. L l . l Requirements for Gas Distribution Pipeline Operators and Large LPG Operators Distribution pipeline operators are required to implement an IM program similar to those required for gas transmission pipelines. PHMSA is adding a new Subpart P - Gas Distribution Pipeline Integrity Management to 49 U.S.C, Part 192 as follows: § 192.1001 What definitions apply to this subpart? § 192.1003 What do the regulations in this subpart cover? § 192.1005 What must a gas distribution operator (other than a master meter or small LPG operator) do to implement this subpart? § 192.1007 What are the requked elements of an integrity management IM plan? § 192.1009 What must an operator report when compression couplings fail? § 192.1011 What records must an operator keep? § 192.1013 When may an operator deviate from required periodic inspections under this part? § 192.1015 What must a master meter or small liquefied petroleum gas (LPG) operator do to implement this subpart? PHMSA is also revising section 192.383, Excess flow valve customer notification. The revised section will be titled "Excess flow valve installation," will eliminate the current requirement for operators to notify customers of the availability of EFVs, and will requke EFVs to be installed on new and replaced service lines serving single family residences. Elements of an IM Plan A gas distribution operator must develop and implement an integrity management program that includes a written integrity management plan as specified in § 192.1007. An integrity management program is an overall approach by an operator to ensure the integrity of its gas distribution system. An integrity management plan is a written explanation of the mechanisms or procedures the operator will use to implement its integrity management program and to ensure compliance with the new subpart P. These operators must also comply with sections 192.1009 through 192.1013. ^ The term "large" is used solely to differentiate these operators from the "small" LPG operators referred to in the rule. Both "large" and "small" LPG operators are small entities for the purposes of the Regulatory Flexibility Analysis. <<>> The IM Plan must address: (a) Knowledge. An operator must demonstrate an understanding of its gas distribution system developed from reasonably available information. (1) Identify the characteristics of the pipeline's design and operations and the environmental factors that are necessary to assess the applicable threats and risks to its gas distribution pipeline. (2) Consider the information gained from past design, operations, and maintenance. (3) Identify additional information needed and provide a plan for gaining that information over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities). (4) Develop and implement a process by which the IM program will be reviewed periodically and refined and improved as needed. (5) Provide for the capture and retention of data on any new pipeline installed. The data must include, at a minimum, the location where the new pipeline is installed and the material of which it is constructed. (b) Identifv threats. The operator must consider the following categories of threats to each gas distribution pipeline: corrosion, natural forces, excavation damage, other outside force damage, material, weld or joint failure (including mechanical couplings), equipment failure, incorrect operation, and other concerns that could threaten the integrity of its pipeline. An operator must consider reasonably available information to identify existmg and potential threats. Sources of data may include, but are not limited to, incident and leak history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, and excavation damage experience. (c) Evaluate and rank risk. An operator must evaluate the risks associated with its distribution pipeline. In this evaluation, the operator must determine the relative importance of each threat and estimate and rank the risks posed to its pipeline. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure. An operator may subdivide its pipeline into regions with similar characteristics (e.g., contiguous areas within a distribution pipeline consisting of mains, services and other appurtenances; areas with common materials or environmental factors), and for which similar actions likely would be effective in reducing risk. (d) Identifv and implement measures to address risks. Determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline. These measures must include an effective leak management program (unless all leaks are repaired when found). (e) Measure performance, monitor results, and evaluate effectiveness. (1) Develop and monitor performance measures from an established baseline to evaluate the effectiveness of its IM program. An operator must consider the <<>> results of its performance monitoring in periodically re-evaluating the threats and risks. These performance measures must include the following: (i) Number of hazardous leaks either eliminated or repaired as required by § 192.703(c) of this subchapter (or total number of leaks if all leaks are repaired when found), categorized by cause; (ii) Number of excavation damages; (iii) Number of excavation tickets (receipt of information by the underground facility operator from the notification center); (iv) Total number of leaks either eliminated or repaired, categorized by cause; (v) Number of hazardous leaks either eliminated or repaired as required by § 192.703(c) (or total number of leaks if all leaks are repaired when found), categorized by material; and (vi) Any additional measures the operator determines are needed to evaluate the effectiveness of the operator's IM program in controlling each identified threat. (f) Periodic Evaluation and Improvement. An operator must re-evaluate threats and risks on its entire pipeline and consider the relevance of threats in one location to other areas. Each operator must determine the appropriate period for conducting complete program evaluations based on the complexity of its system and changes in factors affecting the risk of failure. An operator must conduct a complete program reevaluation at least every five years. The operator must consider the results of the performance monitoring in these evaluations. (g) Report results. Report, on an annual basis, the four measures listed in paragraphs (e)(l)(i)-(e)(l)(iv) of this section, as part of the annual report required by § 191.11. An operator also must report the four measures to the State pipeline safety authority if a State exercises jurisdiction over the operator's pipeline. 1.1.2 Requirements for Master Meter Operators and Small LPG Operators Most master meter operators are small entities and operating their gas distribution pipelines is not their principal occupation. These operators typically have limited on- staff technical pipeline expertise. These operators have historically been treated differently withm Part 192. In particular, they have been subject to more limited documentation requirements. For example, master meter operators and small LPG operators are not required to submit annual reports. Section 192.1015 prescribes IM requirements applicable to these smaller operators. The major elements that these operators are required to include in their IM plans are the same as those in § 192.1007 applicable to other operators. The details of the elements are simplified somewhat, to reflect both the relative simplicity of these pipelines and the limited capability of the operators. For example, the required knowledge of their pipeline is focused on the approximate location and material of which it is constructed and required documentation of this knowledge is limited to documents showing the location <<>> and material of piping and appurtenances that are installed after the effective date of their IM programs and, to the extent known, in existence when the program becomes effective. These operators are not required to submit performance measures, which is consistent with their prior treatment with respect to annual reports. PHMSA is developing guidance suitable for use by master meter and small LPG operators to develop simple IM plans for their pipelines. This guidance will be made available via PHMSA's web site after this final rule is published. The remainder of this report examines the benefits and costs of the regulatory changes are examined, as required by Executive Order 12866 and the Unfunded Mandates Reform Act. The final Regulatory Flexibility Analysis is filed separately in the docket. 2. BACKGROUND The Nation's existing pipeline infrastructure, much of which is over 50 years old, requires regular safety and environmental reviews to ensure its reliability and integrity. To improve safety, PHMSA established Integrity Management requirements in years 2000 and 2002, for operators of hazardous liquid pipelmes (49 CFR 195.452). Subsequently, PHMSA issued E M program regulations for gas transmission pipelines in December 2003 (49 CFR Part 192, Subpart O). Both the hazardous liquid and gas transmission pipeline IM program regulations require operators to analyze risks and focus increased attention on safety, especially the portions of their pipeline that pose the highest risk. This increased attention must include physical inspection (assessment) of the pipe using in-line inspection, pressure testing, or direct assessment, remediation of anomalous conditions following the assessment, continual evaluation of the pipeline, application of additional preventive and mitigative measures, and development of performance measures. Current IM program regulations, however, do not apply to gas distribution pipelines. Gas distribution pipelines deliver gas to residences and other end users and are different from hazardous liquid and gas transmission pipelines. Distribution systems are composed of a grid of "mains" and "service lines." A main is a pipeline that serves as a common source of supply for multiple customers, often located under municipal streets that may be in heavily populated or congested areas. Service lines transport gas from the mains to the meters or customer-owned piping of residential, commercial, and industrial customers. Distribution pipelines can measure as large as 36 inches in diameter; however, most are much smaller, ranging in size from one-half inch service lines to 8 inches in diameter for some mains. These pipelines generally operate at lower pressures than the transmission pipelines and are owned and operated by local distribution companies. Distribution pipelines are constructed of a variety of materials, both metallic and non-metallic. Approximately half of the pipe in distribution systems is plastic. To reach the many end users they serve, distribution pipelines include extensive branching and interconnection, which is significantly different from the long, uninterrupted runs of transmission system pipe. These differences make it impractical to <<>> simply apply gas transmission integrity management requirements to distribution pipelines and instead necessitate integrity management program requirements tailored to distribution pipelines. 3. REGULATORY ANALYSIS Executive Order 12866 dhects 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 or more in any one year. The Order also requires a determmation 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 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. 4. IDENTIFICATION OF THE PROBLEM AND THE NEED FOR THE RULE Although the gas distribution industry is subject to rate regulation, and the regulators act to reflect forces that otherwise would come from the market, the pipeline infrastructure is installed so that the local operator that delivers that product has somewhat of a natural monopoly. Research on this specific industry has indicated that there are no robust market signals or incentives to prompt operators to thoroughly assess the condition of their pipelines or to implement integrity management programs. For example, the Government Accountability Office (GAO) has pointed out in a, study of gas transmission operators'* that the gas transmission integrity management program prompted some ' See: http://www.naturaigas.org/business/industrv.asp: http://www.naturalgas.org/naturalgas/distribution.asp: Fred Foldvary, The Progress Report. http://www.progress.org/fold74.htm. • * GAO, Gas Pipeline Safety, Preliminary Observations on the Integrity Management Program and 7-Year Reassessment Requirement, GOO-06-474T, Testimony Before the Subcommittee on Highways, Transit and Pipelines, Committee on Transportation and Infrastructure, U.S. House of Representatives. Statement <<>> operators to make assessments of their pipelines for the first time. The market structure of the distribution industry may have led to distribution system operators spending less than the socially optimal amount of resources and attention to pipeline integrity. Operators may also have inadequate information to assess the risks associated with gas distribution systems, because they may not have observed incidents involving death or serious injury in any given year (or decade, for that matter), and smaller operators are even less likely to see such incidents. Even though an incident in a particular pipeline is a low probability event, the risk is still inherent in the system itself, and consequences of an incident can be severe. Therefore, the aggregate safety impacts on a national basis justify more significant investment in risk management systems. Recognizing these problems, PIPES Act mandates integrity management programs for distribution systems. Given this statutory mandate, the rest of this analysis seeks to identify the most efficient approach to integrity management. PHMSA considered other means of dealing with the problem before proposing new, comprehensive requirements. PHMSA has examined the feasibility of regulating at the State level. Currently gas pipeline operators are subject to differing State regulations. PHMSA has determined that the diversity in State-specific regulations dictates the need for Federal regulatory oversight. Each State's program must be certified, or subject to an agreement with PHMSA to act on its behalf, as a condition for Federal funding. PHMSA has concluded that a better understanding on the part of operators of the risks posed by their pipeline systems, and a better focus of their actions to address the most significant of those risks is the most effective way to improve the Nation's already- commendable pipeline safety record. Consequently, PHMSA has been implementing integrity management requirements on various pipeline types as part of its program to improve pipeline safety. The historical record shows, however, that more adverse safety consequences result from accidents on distribution pipelines than from those on the pipelines already subject to IM program requirements. Based on PHMSA data from 2001 through 2008, 75 percent to 80 percent of all deaths and injuries occur on gas distribution systems. PHMSA data show that 11 percent of the incidents across all pipeline systems involve deaths or injuries, while the percentage for gas distribution pipelines during the same period is 24 percent and for transmission pipelines it is 3 percent. It is not possible to produce a significant improvement in pipeline safety without addressing distribution pipelines. Therefore, PHMSA has concluded that it is appropriate to establish IM program requirements that will foster a similar understanding of and focus on risk among distribution pipeline operators. In 2004, the DOT Inspector General (IG) pointed out that recent accident trends for gas distribution pipelines were unfavorable and suggested the application of integrity management principles could help improve the safety of distribution pipelines. The IG acknowledged that the reason distribution pipeline operators were exempt from the of Katherine Siggerud, Du-ector, Physical Infrastructure Issues, March 16, 2006. See: http://www.gao.gov/new.items/d06474t.pdf. <<>> regulations was that distribution pipelines could not use the same inspection methods used for hazardous and transmission pipelines. Nevertheless, the IG concluded that there was no reason other elements of integrity management could not be implemented for distribution pipelines. The IG recommended to Congress^ that DOT define an approach for requiring operators of distribution pipeline systems to implement some form of integrity management or enhanced safety program with elements similar to those required in hazardous liquid and transmission pipeline IM plans. The Appropriations Committee then asked PHMSA "to report to the House and Senate Committees on Appropriations by May 1, 2005, detailing the extent to which integrity management program elements may be applied to the natural gas distribution pipeline industry in order to enhance distribution system safety."^ PHMSA submitted the report "Assuring the Integrity of Gas Distribution Pipeline Systems" to Congress in JUne 2(X)5, describing the program used to identify opportunities for improving the safety oi^ distribution pipeline systems. PHMSA developed the program in two phases. Phase 1 identified the nature of requirements that might be imposed and any additional guidance or consensus standards that might be needed to assist operators in implementing any integrity management requirements. Phase 2 included development of appropriate requirements by PHMSA and preparation of guidance/standards by appropriate bodies. During the development of Phase 1, PHMSA involved a large number of key stakeholder groups including State and Federal regulators, representatives from the spectrum of distribution operators, interested members of the public, and representatives of the Nation's fire service. The stakeholders agreed with the DOT IG and Congress's recommendations and concluded that it would be appropriate to modify the regulations to include a risk-based integrity management process for gas distribution pipelines. 5. IDENTIFICATION OF AVAILABLE ALTERNATIVE APPROACHES PHMSA considered several alternatives to assure the necessary protection from potential incidents caused by gas distribution pipelines, with the intention of selecting the alternative that is likely to result in the highest net benefits. PHMSA considered the following approaches: • Apply existing gas transmission pipeline IM program regulations to gas distribution pipelines. • Model State legislation potentially imposing requirements on excavators and others outside the regulatory jurisdiction of pipeline safety authorities. ' "Progress and Challenges in Improving Pipeline Safety," Statement of the Honorable Kenneth M. Mead, Inspector General, Department of Transportation, before the Committee on Energy and Commerce, Subcommittee on Energy and Air Quality, U.S. House of Representatives, July 20, 2004. * House of Representatives report 108-792, November 20, 2004. ^ "Integrity Management for Gas Distribution, Report of Phase 1 Investigations," prepared by Joint Work/Study Groups, December 2005, U.S. DOT/PHMSA - Report: DIMP Phase 1, Doc. Number: RSPA- 2004-19854-70, available at http://dmses.dot.gov/docimages/p84/388302.pdf. 10 <<>> • Develop guidance documents for adoption by States. • Implement prescriptive Federal regulations, specifying in detail, actions that must be taken to assure distribution pipeline integrity. • Implement risk-based, flexible, performance-oriented Federal regulations, establishing high-level elements that must be included in integrity management programs. After considering all the alternatives, PHMSA selected the following alternative: implementation of risk-based, flexible, performance-oriented Federal regulations establishing high-level elements that must be included in integrity management programs. 5.1 Baseline: 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. In response to the mandate concerning IM programs for distribution systems contained in The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (Public Law No: 109-468, Dec. 29, 2006), also known as the PIPES Act, PHMSA is initiating this rulemaking. PHMSA is extending its mtegrity management approach to the largest segment of the Nation's pipeline network—the distribution systems that directly serve homes, schools, businesses, and other natural gas consumers. Begiiming in 2000, the Agency promulgated regulations requiring operators of hazardous liquid pipelines (49 CFR 195.452, published at 65 FR 75378 and 67 FR 2136) and gas transmission pipelines (49 CFR 192, Subpart O, published at 68 FR 69778) to develop and follow individualized integrity management (IM) programs, in addition to PHMSA's core pipeline safety regulations. The Integrity Management approach is designed to promote continuous improvement in pipeline safety by requiring all operators to identify and invest in risk control measures beyond core regulatory requirements existing today. By not taking action, the Agency would be unresponsive to the congressional mandate in the PIPES Act, and there would likely be no reduction in the number of deaths, injuries, or property damages associated with risks related to the integrity management of distribution lines. Although this alternative would not lead to increased compliance costs, there would be no reduction in the societal costs associated with the deaths, injuries, and property damages associated with integrity management improvements. This alternative results in zero net benefits. Thus, this alternative is the baseline for comparison with other alternatives. 11 <<>> 5.2 Apply existing gas transmission pipeline IM program regulations to gas distribution pipelines This alternative was determined by PHMSA to be infeasible. Gas distribution pipelines are different from hazardous liquid and gas transmission pipelines. Distribution systems combine main lines with an almost equal amount of mileage branching from the main lines to connect services to natural gas users. Lines are generally smaller in diameter, operate at much lower pressures, and are constructed of a variety of materials, both metallic and non-metallic. Approximately half of the pipe in distribution systems is plastic compared to very small amounts of plastic gas transmission pipeline. To reach the many end users they serve, distribution pipelines include extensive branching and interconnection compared to transmission systems that have long iminterrupted runs of pipe. These differences substantially distinguish distribution systems from transmission systems, and thus it is not technically feasible to apply gas transmission integrity management requirements to distribution pipelines. For instance, the low pressures, small diameters, and complex connections associated with distribution systems make it infeasible to use smart pigs or hydrotesting, techniques that are used by transmission lines for integrity management. Since a determination has been made that this alternative is not technically feasible to implement, there has been no attempt to estimate impacts. Consequently, no further consideration was given to this alternative. 5.3 Model State legislation, potentially imposing requirements on excavators and others outside the jurisdiction of pipeline safety authorities This alternative was determined by PHMSA to be infeasible because PHMSA could not ensure that any or all of the States adopt the model State legislation. According to the Integrity Management for Gas Distribution Report of Phase I Investigations, experience indicates that this option may not be practical for addressing the broad question of integrity management. The group references the failure of State legislatures to adopt an available model from the Common Ground effort to prevent excavation damage.^ In studying the issue, the study group foimd that model State legislation may be useful for narrower issues, such as improving excavation damage prevention through implementation of comprehensive damage prevention programs, including active enforcement.^ The report concludes, "There are many factors affecting State approaches to regulation. It would be very unlikely that all States could adopt model legislation with sufficient consistency that would represent a national solution to integrity management concerns." The group was composed of representatives of the natural gas distribution industry. State pipeline regulatory authorities, and the public. Integrity Management for Gas Distribution: Report of Phase I Investigations," December 2005. Excavation Damage Group Report, p.71. ^Ibid.p.71. 12 <<>> After careful study, this option is not considered any further as a means of addressing the entire integrity management issue, because the integrity management study group found that the issues surrounding integrity management are broad and require a holistic approach at the Federal level. Not being operationally feasible, this alternative was not considered to be amenable to a comparison of the costs and benefits. 5.4 Guidance documents for adoption by States with the intent of States mandating use of the guidance As with the previous alternative, this alternative was determined by PHMSA to be infeasible because PHMSA could not ensure that any of the States would mandate the use of the guidance, therefore distribution safety would not improve. The Integrity Management for Gas Distribution Report of Phase I Investigations determined that this option is essentially the same as option 5.3 above, except it contemplates States adopting the guidance as mandatory requirements. As with model legislation, the study group considered that adoption likely would not occur in many States. Although the Federal Government establishes basic safety standards, certified States are responsible for regulating intrastate pipelines. The study group notes that States typically have not uniformly adopted recommended approaches in the past. Selecting this option would thus provide only the illusion of a solution. The costs of such an approach would be relatively low, but if the conclusions of the study group are correct, there would also be low beijefits and perhaps, insignificant net benefits. For these reasons, this alternative was not considered any further. 5.5 Prescriptive Federal regulation, specifying in detail actions that must be taken to assure distribution pipeline integrity This alternative was determined by PHMSA to be too inflexible to be applicable to all relevant situations that distribution system operators might confront. The Integrity Management for Gas Distribution Report of Phase I Investigations reaffirms the need for a flexible Federal rule. The study group reasoned that a highly detailed prescriptive regulation would eliminate the flexibility needed to address the unique circumstances of individual States and operators. The study group reported, "The issues important to assuring the integrity of these diverse systems will vary. This diversity makes it difficult for any one prescriptive requirement to address all possible circumstances. It is important that any new requirements that are developed allow sufficient flexibility for the operators of distribution pipeline systems, and the State regulators who oversee their operations, to customize their integrity management efforts to address their specific systems, threats, and issues."'" Although some small operators might prefer a prescriptive regulation, most large operators want the flexibility of a performance-based regulation. The wide range in size and nature of distribution pipeline systems calls for a flexible approach to integrity ' Integrity Management for Gas Distribution. Report of Phase I Investigations. December 2005, p.13-14. 13 <<>> management rather than a single detailed set of requirements. Giving operators the guidance and allowing them to shape it to fit their particular system will assure integrity management efficiently and effectively. A detailed prescriptive rule was deemed by PHMSA to be too inflexible to be applicable to all relevant situations that distribution operators might face, since there is a wide spectrum of distribution operators, from master meter (mostly one-man operation) to large utilities covering thousands of miles of pipelines and over a million customers. Thus a prescriptive rule would be inappropriate and ineffective, resulting in many operators being required to perform tasks not appropriate for their pipeline systems.' These statements of the rule being ineffective and inappropriate suggest that there would likely be a low level of net benefits. For these reasons a prescriptive Federal regulation was evaluated no further. 5.6 Risk-based, flexible, performance-oriented Federal regulation, establishing high- level elements that must be included in integrity management programs This alternative was determined by PHMSA to be practicable and is compared in this document with the baseline "no action" alternative. As will be demonstrated, there are significant net benefits associated with this alternative. This alternative, that is the subject of the rule, creates a high-level, flexible, and performance-based Federal regulation that requires gas distribution operators to develop and implement an integrity management program for their distribution pipeline systems. The regulation requires all operators of a distribution pipeline system to implement an integrity management program and would prescribe minimum requirements each operator must meet in doing so. An integrity management program is intended to manage the risks associated with an operator's pipeline system. An integrity management plan would address, at a minimum, the following elements: • Develop an understanding of their system, periodically reviewing and refining it as needed. • Identify threats (existing and potential). • Evaluate and rank risks. • Identify and implement measures to mitigate risks. • Measure performance, monitor results, and evaluate effectiveness. • Periodically re-evaluate risks and consider the relevance of threats. • Report results. This also embraces the installation of EFVs. An operator would be required to install an EFV on newly installed or replaced service lines that operate continuously throughout the year at a pressure not less than 10 psig and serve a single-family residence, imless doing so would not be practicable. This requirement applies only to new or replaced service " Integrity Management for Gas Distribution: Report of Phase I Investigations," - **truncated:** true - **body characters:** 168931