# Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines

**Citation:** 74 FR 63906  
**Type / status:** rulemaking / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** 2010-02-02  
**Published:** 2009-12-04

PHMSA is amending the Federal Pipeline 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 IM programs required by this rule are similar to those required for gas transmission pipelines, but tailored to reflect the differences in and among distribution pipelines. Based on the required risk assessments and enhanced controls, the rule also allows for risk-based adjustment of prescribed intervals for leak detection surveys and other fixed-interval requirements in the agency's existing regulations for gas distribution pipelines. To further minimize regulatory burdens, the rule establishes simpler requirements for master meter and small liquefied petroleum gas (LPG) operators, reflecting the relatively lower risk of these small pipelines. In accordance with Federal law, the rule also requires operators to install excess flow valves on new and replaced residential service lines, subject to feasibility criteria outlined in the rule. This final rule addresses statutory mandates and recommendations from the DOT's Office of the Inspector General (OIG) and stakeholder groups.

## Document text

Federal Register, Volume 74 Issue 232 (Friday, December 4, 2009) [Federal Register Volume 74, Number 232 (Friday, December 4, 2009)] [Rules and Regulations] [Pages 63906-63936] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: E9-28467] [[Page 63905]] ----------------------------------------------------------------------- Part III Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Part 192 Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines; Final Rule Federal Register / Vol. 74, No. 232 / Friday, December 4, 2009 / Rules and Regulations [[Page 63906]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 192 [Docket No. PHMSA-RSPA-2004-19854; Amdt. 192-113] RIN 2137-AE15 Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: PHMSA is amending the Federal Pipeline 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 IM programs required by this rule are similar to those required for gas transmission pipelines, but tailored to reflect the differences in and among distribution pipelines. Based on the required risk assessments and enhanced controls, the rule also allows for risk-based adjustment of prescribed intervals for leak detection surveys and other fixed-interval requirements in the agency's existing regulations for gas distribution pipelines. To further minimize regulatory burdens, the rule establishes simpler requirements for master meter and small liquefied petroleum gas (LPG) operators, reflecting the relatively lower risk of these small pipelines. In accordance with Federal law, the rule also requires operators to install excess flow valves on new and replaced residential service lines, subject to feasibility criteria outlined in the rule. This final rule addresses statutory mandates and recommendations from the DOT's Office of the Inspector General (OIG) and stakeholder groups. DATES: Effective Date: This Final Rule takes effect February 2, 2010. Comment Date: Interested persons are invited to submit comment on the provisions for reporting failures of compression couplings by January 4, 2010. At the end of the comment period, we will publish a document modifying these provisions or a document stating that the provisions will remain unchanged. ADDRESSES: Comments limited to the provisions on reporting failures of mechanical couplings should reference Docket No. PHMSA-RSPA-2004-19854 and may be submitted in the following ways: E-Gov Web site: http://www.regulations.gov . This site allows the public to enter comments on any Federal Register notice issued by any agency. Fax: 1-202-493-2251. Mail: DOT Docket Operations Facility (M-30), U.S. Department of Transportation, West Building, 1200 New Jersey Avenue, SE., Washington, DC 20590. Hand Delivery: DOT Docket Operations Facility, U.S. Department of Transportation, West Building, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC 20590 between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. Instructions: In the E-Gov Web site: http://www.regulations.gov , under ``Search Documents'' select ``Pipeline and Hazardous Materials Safety Administration.'' Next, select ``Notices,'' and then click ``Submit.'' Select this rulemaking by clicking on the docket number listed above. Submit your comment by clicking the yellow bubble in the right column then following the instructions. Identify docket number PHMSA-RSPA-2004-19854 at the beginning of your comments. For comments by mail, please provide two copies. To receive PHMSA's confirmation receipt, include a self-addressed stamped postcard. Internet users may access all comments at http://www.regulations.gov , by following the steps above. Note: PHMSA will post all comments without changes or edits to http://www.regulations.gov including any personal information provided. FOR FURTHER INFORMATION CONTACT: Mike Israni by phone at (202) 366-4571 or by e-mail at [email protected] . SUPPLEMENTARY INFORMATION: I. Background Existing integrity management regulations cover 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). These regulations require that operators of these pipelines develop and follow individualized integrity management (IM) programs, in addition to PHMSA's core pipeline safety regulations. The IM approach was designed to promote continuous improvement in pipeline safety by requiring operators to identify and invest in risk control measures beyond core regulatory requirements. PHMSA published a Notice of Proposed Rulemaking (NPRM) on June 25, 2008, (73 FR 36015) to extend its integrity 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 gas distribution pipelines and gas transmission or hazardous liquid pipelines made it impractical 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. PHMSA worked with a number of multi-stakeholder groups to help determine the best way to apply integrity management principles to distribution pipelines before publishing the NPRM. The work and conclusions of the stakeholder groups are described in the NPRM. As described in the NPRM, the proposal was responsive to recommendations from DOT's Inspector General and the National Transportation Safety Board. It also proposed to implement a requirement in the Pipeline Inspection, Protection, Enforcement and Safety Act (PIPES Act) of 2006 that integrity management requirements be established for distribution pipelines. The proposed rule also included a provision to allow distribution pipeline operators to apply for approval from their safety regulators to adjust the intervals at which they perform specific safety requirements that current regulations require to be performed at specified intervals. This provision recognized the basic principle underlying integrity management--that operators should identify and understand the threats to their pipelines and apply their safety resources commensurate with the importance of each threat. Operators devote resources to comply with the core pipeline safety regulations. These safety resources can be made available for other purposes where a low level of risk makes a longer interval acceptable. Applying those resources to other safety tasks to address higher risks can result in an overall improvement in safety. In addition, the proposed rule would have required distribution pipeline operators to install excess flow valves (EFV) in certain new and replaced residential service lines. This provision also implemented a requirement in the 2006 PIPES Act. [[Page 63907]] II. Comments on the NPRM PHMSA received 143 letters commenting on the proposed rule. Of these: 12 were from associations. This includes national and regional associations of gas distribution pipeline operators and the National Association of Pipeline Safety Representatives (NAPSR), the Association of State Pipeline Safety Regulators. 62 were from municipal distribution pipeline operators. 45 were from non-municipal local distribution pipeline operators. 15 were from State pipeline safety agencies. 5 were from companies supplying products and services to the industry. 1 was from a citizens' group. 1 was from the Plastic Pipe Database Committee (PPDC). 1 was from the Gas Piping Technology Committee (GPTC). 1 was from an anonymous commenter. General Comments Virtually all comment letters supported the proposed rule, with notable exceptions for some of its provisions. The vast majority of commenters commended PHMSA for the inclusive way in which the background for the proposed rule was developed. Most commenters who took exception to particular provisions in the proposed rule objected to those provisions as being beyond what stakeholder groups had suggested. The anonymous commenter suggested that the proposed rule is not needed and noted that accidents happen. One operator suggested that this entire proposal is unnecessary, since existing rules are adequate to assure safety. One operator also opposed the proposed rule, noting that system differences mean that the concepts used on transmission lines do not apply to distribution and suggesting that the burden of implementing integrity management for distribution pipelines would cause more harm than good. One state pipeline safety regulatory agency also opposed the proposed rule, noting that the existing body of regulations has resulted in a very low number of deaths annually from distribution pipeline accidents and suggesting that the new requirements would therefore not be cost-beneficial. The State agency also noted that the new rule will impose additional work on already- burdened State pipeline safety regulators. PHMSA has considered these comments but still considers it necessary to issue a rule requiring integrity management for distribution pipelines. While accidents may continue to occur, that does not mean that reasonable actions should not be taken to avoid those accidents that could be prevented. PHMSA concludes that the flexibility inherent in the rule, as modified in response to other comments (described below), adequately addresses concerns based on differences among distribution pipelines. PHMSA also concludes that the changes made in response to other comments will reduce implementation costs and that the rule will be cost-beneficial. PHMSA is working with State pipeline safety agencies to increase the level of Federal financial support provided for State programs. PHMSA notes that the vast majority of distribution pipeline operators and State regulators, and the associations that represent them, supported the proposed rule. The existing rules help assure an admirable safety level. Still, significant accidents continue to occur, if infrequently. Experience has shown that incidents are most often caused by a combination of circumstances. These circumstances represent risks for the pipeline involved, but may not affect other pipelines. It is thus not practical to create additional prescriptive requirements to address these pipeline-specific risks. This rule (as the integrity management requirements for other types of pipelines that preceded it) requires that operators evaluate their pipelines to identify the risks important to their circumstances and take appropriate actions to address those risks. This IM regulation for distribution operators requires an operator to conduct a comprehensive evaluation of its system to better identify threats to the system, to implement additional measures to help prevent accidents from occurring and to mitigate the consequences if an accident does occur. IM provides for a more systematic and comprehensive approach to preventing failures. Accordingly, PHMSA considers this the most effective means to effect further reductions in the number of pipeline incidents. The regulatory analysis supporting this rule considers the improvement in safety that is expected to result and explicitly recognizes the current low frequency of serious accidents. Specific Comments There was a broad consensus among commenters that several provisions in the proposed rule should be deleted or significantly modified. In most cases, the consensus included parties from ``commercial'' and municipal operators (and their associations) and State regulators. Many additional comments were made, often suggesting specific changes needed to improve the proposed rule or to make clear the actions required to comply. These comment topics are: Comment Topic 1 Plastic Pipe Reporting. Comment Topic 2 Performance Through People. Comment Topic 3 ``Damage'' Definition. Comment Topic 4 Implementation Time. Comment Topic 5 Rule Structure and Implementation. Comment Topic 6 Alternative Intervals. Comment Topic 7 IM Requirements for Master Meter and LPG Operators. Comment Topic 8 Transmission Lines Operated by Distribution Operators. Comment Topic 9 Part 192--Requirement References. Comment Topic 10 Hazardous Leak Definition. Comment Topic 11 Required Documentation. Comment Topic 12 Excess flow valves. Comment Topic 13 Guidance. Comment Topic 14 Leak monitoring. Comment Topic 15 State authority. Comment Topic 16 IM program evaluation and improvement. Comment Topic 17 Permanent marking of plastic pipe. Comment Topic 18 Continuing surveillance. Comment Topic 19 Information gathering. Comment Topic 20 Knowledge of pipeline. Comment Topic 21 Threat identification. Comment Topic 22 Risk assessments. Comment Topic 23 Performance measures. Comment Topic 24 Regulatory analysis. Comment Topic 25 IM for new pipelines. Comment Topic 26 Annual report form. A discussion of each comment topic and PHMSA's response to each follows: Comment Topic 1: Plastic pipe reporting. Commenters universally rejected the proposal to require reporting of all plastic pipe failures. Commenters noted that the plastic pipe data committee (PPDC) includes representatives of all stakeholder groups and has several years of data for identifying trends that would be lost if PPDC were no longer used. Commenters believe PPDC has done an excellent job of collecting and analyzing operating experience with plastic pipe. According to commenters, operators of approximately 75 percent of installed plastic pipe mileage voluntarily provide information to PPDC. While this is less than the 100 percent participation that would result from a mandatory reporting requirement, commenters maintained this is sufficient data to draw statistically significant conclusions about the performance of all plastic pipe. Many commenters thought PHMSA's concern that information from PPDC is [[Page 63908]] not available to the entire industry is unjustified. These commenters noted that PPDC issues summary reports, that trade associations (who participate in PPDC) provide information to their members, and that PHMSA has issued advisory bulletins concerning significant PPDC conclusions. Many operators commented that they would not have the time or resources to review detailed failure information on their own, and that the information currently provided by the trade associations and PHMSA advisories is useful to them. Some commenters suggested that the rule require operators to make use of this information. AGA and one operator suggested that the requirement to report plastic pipe failures be replaced with a requirement that operators consider industry and government advisories in evaluating plastic pipe performance as part of their DIMP programs. They believe this would be more effective in addressing PHMSA's underlying concern of operators not considering relevant information than would mandatory reporting. All who addressed this subject agreed that replacing the current system with mandatory reporting of all failures would be unreasonably burdensome and would not improve knowledge or safety. PPDC commented that mandatory reporting is not needed as they have the necessary structure and participation. PPDC suggested that it would take years to collect enough data to duplicate the information they already have on hand. PHMSA response: PHMSA is persuaded that the data collection burden is not warranted at this time given the current system of PPDC analysis of plastic pipe failure trends and dissemination of lessons learned from this analysis via PPDC reports and trade association communications and through our advisories. The final rule does not include the requirement to report all plastic pipe failures. The proposed requirement included reporting failures of couplings used with plastic pipe. PHMSA has retained this requirement for compression couplings. This final rule includes a requirement that operators report failures of compression coupling as part of their annual reports. This provision was an included part of proposed Sec. 192.1009, which would have required reporting of ``each material failure of plastic pipe (including fittings, couplings, valves and joints)'' (emphasis added). As described above, PHMSA has deleted from the final rule the requirement to report plastic pipe failures, since it was persuaded by the public comments that PPDC is adequately collecting and analyzing this data and disseminating the results of its analysis broadly. PPDC does not, however, collect data on couplings used to join plastic pipe, since the body of most couplings is metal. Coupling failure has been the cause of a number of incidents on distribution pipelines in recent years and the subject of several PHMSA advisories. Additional data concerning coupling failures is needed to enable PHMSA to determine if additional requirements are needed to help prevent future incidents from coupling failure. Accordingly, PHMSA has retained the included element of reporting of coupling failures in this final rule. The final rule provision is not limited to couplings used on plastic pipe. PHMSA understands that the principal use for couplings in distribution pipeline systems is to connect plastic pipe or to connect plastic pipe to metal pipe (including risers, etc.). PHMSA recognizes that it is possible for mechanical couplings to be used to connect metal pipe to metal pipe, and that reporting of failures involving such connections would not have been encompassed by the proposed requirements related to plastic pipe in the NPRM. PHMSA believes that use of couplings in applications that do not involve plastic pipe is rare. Nevertheless, PHMSA invites public comment on the extension of this proposed requirement to include reporting of failure of couplings used in metal pipe. Comments should be submitted by January 4, 2010. Based on the comments we receive, we will consider modifying the provision. At the end of the comment period, we will either issue a modification or a notice stating that the section stands as written. An operator is not required to collect coupling failure information until January 1, 2010. We expect to issue any modifications to this section prior to that date. If we are delayed in issuing a modification, we will then consider further delaying the compliance date for section 192.1009. PHMSA is issuing, in conjunction with this final rule, a 60-day notice regarding amendments to the Annual Report form, which includes changes related to this reporting requirement. Until PHMSA announces a modification, operators should plan to report the information described in the 60-day notice. Comment Topic 2: Performance through people. Commenters opposed the performance through people (PTP) element and the proposed requirement that each IM plan include a section entitled ``Assuring Individual Performance.'' Commenters maintained that the proposed requirement is vague and likely unenforceable and that it creates confusion and diminishes the focus on the core issues of importance to IM. They pointed out, as did PHMSA in the NPRM's preamble, that other regulations currently address the impact of people on pipeline safety. These regulations include Operator Qualification, Drug and Alcohol requirements, Damage Prevention, and Public Awareness. Commenters noted that the proposed PTP requirement is unclear about what, if any, additional actions are expected, and that having to refer to actions taken under these other requirements in an IM plan creates an unnecessary additional paperwork burden. NAPSR, American Public Gas Association (APGA), GPTC, and operators suggested that PHMSA should not presume that action is required by all operators to address the threat of inappropriate operation. These commenters noted that studies, including those conducted by the American Gas Foundation (AGF) and Allegro and referred to in the preamble of the NPRM, have shown that this threat poses a very small risk; PHMSA data shows it to be the cause of only 3% of all leaks. PHMSA response: PHMSA has not included PTP requirements in the final rule. PHMSA agrees the provision is largely duplicative of other existing regulations. Nevertheless, the final rule still requires that operators evaluate all threats applicable to their pipeline systems. Thus, operators for which inappropriate operation is a threat of concern will be required to address that threat. Comment Topic 3: ``Damage'' definition. In the NPRM, PHMSA proposed to add a new definition for ``damage'' applicable to the IM subpart. The proposed definition was ``any impact or exposure resulting in the repair or replacement of an underground facility, related appurtenance, or materials supporting the pipeline.'' This term is being defined because of a provision in the proposed rule that would require reporting the number of excavation ``damages'' as a performance measure. Industry stakeholders universally commented that the definition of ``damage'' should be limited to excavation damage and to damage that causes loss of gas (immediate leaks). GPTC would further limit the definition to ``known'' excavation damage. States and NAPSR suggested defining excavation damage vs. damage, but did not suggest limiting damage of interest to damage causing leaks. One operator [[Page 63909]] suggested that the definition should also include instances in which damaged pipe is retired in place because damaged pipe and appurtenances are not always repaired or removed; the operator suggested that the definition should focus on the unplanned nature of the repair, removal or retirement. The commenters pointed out that operators report data regarding leaks in their annual reports but not other damage. Operators are not now required to collect data on damages that do not result in leaks. Commenters contended that extending the definition of damage to encompass situations that do not cause leaks will cause loss of continuity with previous data and may cause confusion. Some noted that statistically better conclusions can be drawn if such continuity is maintained. Some commenters asked whether coating damage or damage to anodes/test wires would be included. Others noted that discovery of latent damage, that may have occurred years earlier, is not a measure of the current effectiveness of a damage prevention or integrity management program. Industry expressed concern about the additional recordkeeping burden associated with capturing data on non-leak damages. Two operators suggested that the term ``exposure'' be eliminated from the proposed definition of damage (or excavation damage) because it is unclear what this term adds. They question, for example, whether washouts would be included. PHMSA response: PHMSA agrees that excavation damage is of principal concern and is the term that should be defined. PHMSA does not agree, however, that only excavation damage that results in a leak is of concern. Mitigating the threat of excavation damage means implementing or continuing actions that will minimize the likelihood that excavation near the pipeline will cause damage. Operators must seek to prevent excavation ``hits'' of the pipeline, whether a hit results in leakage or not (e.g., a glancing blow or insufficient force to cause a leak). That a hit occurs, regardless of whether it causes leakage, is an indication that the actions intended to prevent such an occurrence have failed. Operators cannot adequately evaluate the effectiveness of their mitigative actions for this threat, and PHMSA cannot evaluate the effectiveness of these actions on a national level, if non-leak events are excluded. Assuring continuity with past data is less important than assuring that the data being collected appropriately addresses the event of concern. At the same time, PHMSA is sympathetic to the need to have well- defined criteria identifying what damage is to be included in performance monitoring and understands that a definition based on whether a leak occurred would provide clarity; however, it would not allow operators and PHMSA to monitor the effectiveness of damage prevention measures. Pipeline operators, as well as operators of all underground facilities, need to evaluate the effectiveness of damage prevention efforts. The Common Ground Alliance (CGA) is a national group involving operators of all types of underground facilities, as well as representatives of excavators and others who play a part in preventing damage to underground facilities. CGA has established the Damage Information Reporting Tool (DIRT) to collect information submitted voluntarily concerning damage to underground facilities. Some pipeline operators participate in DIRT. DIRT defines damage based on whether repair or replacement of an underground facility is required. This is very similar to the definition proposed in the NPRM, which also relied on the need to repair or replace as the defining criterion. PHMSA has modified the definition in the final rule to match more closely the language used in the DIRT definition of excavation damage. PHMSA has omitted the phrase ``of exposure'' used in the DIRT definition, since this refers to damage from causes other than excavation (e.g., washout). The changes in the definition in the final rule will provide the needed clarity and will also facilitate potential comparison of distribution pipeline damage prevention performance to that of other underground facilities for which CGA collects data. This change also obviates the need to include retirement in the definition because retirement of an active pipeline will usually involve replacement or bypass. Damage to the protective coating or to the cathodic protection that requires repair/replacement is damage of concern in evaluating the effectiveness of damage prevention measures; therefore, the definition in the final rule clarifies that damage necessitating repair to coating or to cathodic protection constitutes excavation damage. Comment Topic 4: Implementation time. Many industry commenters objected to the requirement that IM plans be ``fully implemented'' within 18 months. They suggested that ``fully'' be deleted. IM plans inherently involve learning more about the pipeline systems and associated risks, and it is not clear when they will be ``fully'' implemented. A few operators suggested we clarify what is meant by ``implement.'' They noted that it was not clear if this meant that all databases must be fully populated and that, if so, it cannot be accomplished in 18 months. Many industry commenters also objected to the proposed requirement that implementation occur within 18 months. They argued that many operators will need to make changes in how they collect and manage data, including the need to purchase new computers and develop new databases or make other IT changes, and that these changes take time. Industry also suggested that it is not practical to expect that plans will be implemented, databases will be fully populated, etc., for all portions of complex distribution systems in a short period of time. AGA noted that Congress allowed 10 years for full implementation of gas transmission IM. Commenters varied in their suggestions for a different implementation deadline. Many suggested 24 months, with one operator clarifying that after such a period operators should be required to have developed and implemented a ``framework'' that will further develop over time. One operator suggested one year to develop plans/programs and another year to implement. Others suggested variations on this approach, with 1\1/2\ years allowed either for development or implementation. One operator commented that the proposed rule was too ambiguous as to the actions required to implement its provisions. It stated that the rule lacks the clarity needed to know what must be done. PHMSA response: PHMSA has deleted the term ``fully'' from the final rule. PHMSA has retained the 18-month requirement. PHMSA recognizes that implementing IM plans involves learning and revision but does not agree that this means it is necessary to stretch out the implementation deadline. It is important to implement--to begin the iterative learning process--as soon as practical. With ``fully'' being deleted, as noted above, it is clear that implementation is not expected to mean that all problems have been identified and resolved. PHMSA notes that 18 months is consistent with the period suggested by many commenters for developing IM programs and, with deletion of the concept of ``fully implement,'' believes this period is still appropriate. AGA's comment is incorrect. Congress allowed 10 years for gas transmission operators to complete baseline [[Page 63910]] assessments (i.e., physical inspection) of the portions of their pipelines in high consequence areas.\1\ The proposed rule did not include a provision for distribution pipeline operators to conduct such assessments. Transmission pipeline operators were required to develop and implement IM plans in one year.\2\ --------------------------------------------------------------------------- \1\ Pipeline Safety Improvement Act of 2002, Section 14. \2\ 49 Code of Federal Regulations, Section 192.907. --------------------------------------------------------------------------- PHMSA disagrees with the comment that the rule is ambiguous. This comment was not echoed by the many other operators or the trade associations that submitted comments. Some commenters identified specific areas where they believed further clarity was needed and PHMSA has made changes where appropriate, as described below. As a result, PHMSA concludes that the actions required to implement the final rule are clear. Comment Topic 5: Rule structure and implementation. Several commenters addressed specific issues associated with the structure of the rule and language in proposed Sec. 192.1005 addressing what gas distribution operators must do to implement this new subpart. A consultant and GPTC both suggested that section headers within the rule not be written as questions because questions are inherently longer than classic titles, and make the rule harder to use. AGA and several distribution operators objected to the proposed requirement that procedures describe the ``processes'' for developing, implementing and periodically improving IM elements. The Iowa Utilities Board (Iowa) also suggested that this provision be modified to remove the reference to processes. The commenters noted that the term is unclear and could be interpreted to require elaborate algorithms. They noted that the stakeholders concluded that major technical changes are not needed, which they interpret to mean that major ``processes'' are not required to implement distribution IM. They believe that deleting the term does not affect the meaning of the proposed requirement. PHMSA response: The structure of the regulation as question and answer is part of the long-standing Government-wide requirement to write regulations in ``plain English.'' PHMSA has been consistently using this format in its pipeline rulemakings for some time. PHMSA has revised Sec. 192.1005(b) to delete the reference to ``processes.'' Comment Topic 6: Alternative intervals. Commenters generally favored the proposed requirement that would allow operators to propose alternative intervals for part 192 requirements. There were a number of comments related to this provision and its implementation. a. Concept. AGA, GPTC, and many gas distribution operators supported the proposal. They noted that shifting of resources often is necessary to assure safety efficiently. They believe that the proposed rule would not be cost-beneficial unless it allowed for such adjustments. They noted that risk-based intervals are more effective and efficient and can result in improved safety and reduced costs. In response to a preamble question concerning advantages and disadvantages of allowing operators to adjust required intervals, some operators commented that the engineering work needed to establish new intervals and the need for State review and understanding of the basis were disadvantages of PHMSA's proposal. PHMSA response: This provision is intended to facilitate realignment of safety resources, where appropriate, to promote efficiency without compromising safety. Because operators are in the best position to understand the risks on their system, and where resources should be effectively applied, this provision is designed to give operators that latitude to effectively manage their systems. Approval from regulators is necessary to prevent the abuse of this provision. Operators are not required to apply for adjusted intervals. If the burden of engineering work and seeking State review are too burdensome, the operator may continue to use the intervals in the regulations. b. Process. AGA, GPTC, and several operators suggested that it will be important for PHMSA to provide guidance to the States for implementing alternative intervals. One operator suggested a federal ``template'' to be used by the States. Commenters suggested that consistency would be particularly important for large companies that operate pipelines in multiple states. One commenter stated the process should be ``streamlined.'' NAPSR, however, asserted that approval should be per State procedures, with flexibility provided for each State to consider its particular circumstances. Iowa also noted that such guidance is not needed. The Massachusetts Department of Public Utilities suggested that a process needs to be defined for appeal of decisions related to proposals for alternative intervals. They believe that such a process should be consistent with that for waivers under 49 U.S.C. 60118. PHMSA response: State authority and regulatory structures differ, and some state regulators may need to seek additional authority (from their state government) to implement this provision. States will implement this provision under individual state statutory authority in accordance with the applicable certification under 49 U.S.C. 60105 of this title or agreement under section 60106. PHMSA believes most states will be able to establish procedures under existing authority and may already have procedures that can be used for this purpose. PHMSA agrees with NAPSR that states need flexibility in implementing this provision. PHMSA will develop criteria for evaluating operator's alternative interval proposal in the states where PHMSA exercises enforcement authority over distribution pipelines. States may be able to use those criteria where they exercise enforcement authority. Factors important to each regulatory authority's consideration of proposed changes to intervals for safety actions are also likely to differ. These differences make it impractical to develop a common ``template'' process. PHMSA agrees that the regulatory authority responsible for reviewing the request should institute appropriate administrative procedures for processing requests for alternative intervals, to include a process for appealing a decision. States will establish their own procedures for review, and it is not appropriate for PHMSA to impose a ``streamlined'' process on state actions. c. Approving agency. NAPSR, States, and some industry commenters suggested that the rule be clarified that approval must be requested from the regulatory authority exercising jurisdiction. They considered the language in the proposed rule vague as to whether a state or PHMSA was the approving agency, or whether an operator could apply to either. One operator suggested that approval should be by States. PHMSA response: PHMSA has always intended that the alternative interval provision in this rule would allow the regulatory authority exercising jurisdiction over the operator of the distribution pipeline to act on a proposal to use alternative intervals. We have clarified the language in the final rule to remove any implication that an operator may seek approval from either [[Page 63911]] PHMSA or a state. Most distribution pipelines are regulated by state agencies and approval of changes proposed by those operators will be by the state. d. Evaluation of proposals. A number of commenters addressed the proposed requirement that operators proposing alternative intervals demonstrate that a reduced frequency will not significantly increase risk. NAPSR proposed that operators should be required to demonstrate enhanced system safety or, at minimum, that operation would be at least as safe under the proposed alternative. Iowa suggested a requirement for a substantially equal or superior level of safety. One operator requested that the meaning of a significant increase in risk be clarified by example, noting that the proposed language is unclear. Another suggested that the rule should not require a proposal for an alternative interval to include a no- significant-risk demonstration; the commenter noted that the core pipeline safety regulations are not risk based and suggested that risk must be considered on an overall basis vs. change-by-change. Although commenters generally supported consistency between regulatory authorities, commenters also suggested that there is no single basis for judging the adequacy of the engineering basis for a proposed change, and that it is not practical or necessary to define requirements for performance/data analysis. One operator suggested that engineering analyses should be judged on whether they are performed by an engineer, are subject to internal review, use good data, and include logical analyses and conclusions. GPTC and one operator suggested that no additional analysis should be required if performance measures show that risk mitigation is effective. AGA and several commenters noted that there should be no arbitrary limit on the change in interval that will be allowed. PHMSA response: The rule does not require and PHMSA does not contemplate that operators will produce a precise quantitative estimate of risk. Accordingly, PHMSA recognizes that it is not easy to demonstrate that any action produces no significant increase in risk. However, regulating safety requires judgments weighing risk versus costs. Judgments of this type are what operators will need to support their proposals and regulators will need to consider. PHMSA does not agree that any reduction in safety intervals is unacceptable because the change alone would result in some increase in risk. Instead, the regulatory authority needs to make an overall judgment on the adequacy of proposed changes. PHMSA has revised the final rule to require that alternatives, as part of the overall IM plan, provide an equal or improved overall level of safety. This change is intended to eliminate any implication that a quantitative estimate of risk is required. PHMSA expects that operators will be conscientious in demonstrating that proposals produce a level of safety that is equal or improved, on an overall basis, and that states will be reasonable in judging the adequacy of proposed changes. PHMSA also agrees that it is unnecessary and likely impractical to establish specific criteria for approval of proposals for alternative intervals. Each proposal must be considered as a whole and on its own merits. PHMSA has not adopted any of the various alternatives suggested by commenters because each regulatory authority must exercise its judgment based on the circumstances of each request. However, PHMSA also recognizes the industry's need for some degree of consistency in how proposals are evaluated. PHMSA intends to work with the states to help assure a degree of consistency. PHMSA is not specifying any limit on the intervals that may be authorized by the regulatory authority. The regulatory authority will be responsible for determining safe intervals based on the information in each operator's proposal. e. Opposition. The Florida Public Service Commission opposed the proposal to allow alternative intervals. The Commission maintained that waivers (their characterization) inherently reduce the established minimum safety level. They believe that processing these proposals will be burdensome and that proposed waivers would generally not be approved. If the provision is retained, they suggest that the risk analysis used as a basis for changes must be transparent to the regulator. They also suggest that the code be revised to require that operations and maintenance (O&M) plans be required to contain a summary of maintenance tasks and approved periodicity, since it will no longer be possible to use a common inspection template if operators are not required to conduct actions at the same intervals. PHMSA response: Waivers from regulatory requirements (sometimes also called special permits) are a common regulatory tool. PHMSA permits pipeline operators to seek a special permit \3\ and considers such requests on their merits. Although required periodic actions address threats of concern and a reduction in the periodicity of those actions inherently involves an increase in risk, adjustments to the frequency may be warranted when safety resources are applied to other areas of greater concern. Contrary to the assertion of the commenter, the use of waivers can result in a reduction in overall risk (i.e., improvement in safety), and regulators must make judgments regarding the overall effect of proposed changes. --------------------------------------------------------------------------- \3\ 49 United States Code, Section 60118. --------------------------------------------------------------------------- The final rule requires that the regulatory authority make the decision to approve or disapprove any proposal for alternative intervals. PHMSA sees no need to add a requirement that risk analyses used for this purpose be ``transparent'' to regulators because an operator will have to work with the regulatory authority to provide enough information to evaluate the requested change. PHMSA also does not agree that a requirement that each O&M plan contain a summary of maintenance tasks and periodicity is needed. Florida, or other states, may require such changes or other information needed to facilitate their inspections as part of their process of reviewing an operator's proposal. f. Costs and benefits. Commenters generally agreed that any additional cost to states should be minimal. (NAPSR concurred, provided that States are allowed to follow their current procedures.) Some comments suggested that the alternative interval provision will be of limited benefit. One operator suggested that the proposed requirement is too burdensome, involving significant administrative costs and burden associated with the need to use risk analyses to justify all changes. Another noted that there are limitations on the ability of operators to move resources from low-risk areas, including potential changes to labor agreements and reassignment of personnel. They requested that the rule recognize these limitations. Some operators are concerned that failure of state regulators to approve alternative intervals will result in implementing additional actions to control risks without offsetting reductions where risk is low, thus increasing total costs. PHMSA response: Cost issues are addressed in the Regulatory Impact Analysis and the Regulatory Flexibility Analysis located in the docket for this rulemaking. This provision imposes no burden on operators. Use of alternative intervals is voluntary. Operators who conclude that obtaining approval would be too burdensome or that it would be too difficult to realign safety resources need [[Page 63912]] not apply. PHMSA therefore sees no need to revise the rule language to recognize that such situations may exist. Operators apply safety resources to purposes other than inspections/actions required periodically by regulation. Operators will be able to realign those resources without regulatory approval, based on insights that their risk analyses may supply, providing a means by which they can make their safety activities more efficient, thereby permitting them to avoid increased costs. g. An industry consultant suggested that the current requirement to inspect inside meter sets for atmospheric corrosion at 3-year intervals should be changed. He noted that experience shows these inspections are not needed and it is more efficient to change the requirement on a national basis. PHMSA response: This is an example of a required periodic inspection where an operator could propose a modification if its analysis showed devoting resources in another area would be more beneficial from a safety standpoint. Changing this periodic requirement on a national basis is outside the scope of this rulemaking. h. Some operators suggested that implementation of alternative intervals should be allowed, based on risk analysis, without requiring regulatory approval. They noted that reductions in effort, where found appropriate, are an integral part of implementing a risk-based approach. They expressed concern that state regulators will be unwilling to approve reductions from established intervals which, although not risk-based, are an accepted norm. PHMSA response: PHMSA does not think regulatory approval should be eliminated. Regulatory oversight is appropriate for changes that involve reducing safety actions currently required by regulation. PHMSA recognizes that there may be some reluctance to approve reductions from an established norm; however, PHMSA plans to assist states to determine appropriate methods to evaluate proposals. PHMSA believes that these efforts will serve to address any reluctance on the part of state regulators to consider alternative intervals. Comment Topic 7: IM requirements for master meter and LPG operators. Many comments addressed the proposed limitation of requirements for master meter and LPG operators (MM/LPG) and PHMSA's request for comment on these limitations. PHMSA asked whether the proposed limitations were appropriate, whether further limitations were needed or if these operators should be exempt from IM requirements. PHMSA also asked whether similar limitations should be afforded to other types of operators. a. Proposed limitations are inappropriate. Two major trade associations addressed the proposed limitations for master meter and LPG operators. (Neither group's members include operators of this size.) AGA suggested that these smaller operators should be required to implement distribution IM, but that the requirements should be scalable, recognizing the uncomplicated nature of their facilities. APGA agreed that MM/LPG should not be excluded from IM requirements. They noted that if mandatory reporting of plastic pipe damages is eliminated (as they suggested) the limitation essentially becomes an exclusion from filing annual reports. Master meter operators are currently excluded from annual report requirements. APGA ``would not object'' to adding a requirement that master meter and LPG operators evaluate and prioritize risk. APGA sees risk ranking as an integral part of assessing risks, and believes it will occur whether or not it is required explicitly in the rule. NAPSR, Connecticut Department of Public Utility Control, Pennsylvania Public Utility Commission (PPUC), and several operators also commented that MM/LPG should be subject to IM requirements. They referenced the conclusion of the stakeholder groups that distribution IM should apply to all distribution operators. These commenters did not agree that these operators pose less risk, and maintained that simpler systems will inherently have simpler programs. They also noted that some master meter operators are much larger than the NPRM stated. PPUC explained that there are two master meter operators in its state with more than 6,000 customers. Other commenters noted that there is limited data on these systems, since they do not report incidents, and thus the risk may not be small. The Arizona Corporation Commission (AZCC) commented that all LPG operators should not be treated like master meters, since some serve small towns, like local distribution companies and have the same limited control over the principal threat of excavation. AZCC suggested that LPG operators who serve a city, town, or other municipality within a specified service area as defined by the state agency with authority should meet the same requirements as other distribution system operators. AGA and NAPSR noted that LPG poses unique risks because the product is heavier than air, unlike natural gas. Leaks from these systems will not safely disperse, as will leaks from natural gas distribution systems. PHMSA response: PHMSA is persuaded that there is a reasonable criterion to distinguish between LPG operators. PHMSA's concern with overwhelming small operators with limited resources and technical expertise is not applicable to LPG systems serving hundreds or thousands of customers because those operations are more like small natural gas distribution system operators. PHMSA notes that existing regulations include a criterion to differentiate between large and small LPG operators. Section 191.11 excludes LPG operators serving fewer than 100 customers from a single source from filing annual reports. Other LPG operators are required to file such reports. PHMSA has revised the final rule to embrace this same criterion. LPG operators serving fewer than 100 customers from a single source are treated like master meter operators. Other LPG operators must meet the same requirements as natural gas distribution pipeline operators. We are also persuaded that MM/small LPG operators should not be exempt from ranking risks--a requirement we had applied to all other distribution operators in the proposed rule. We believe that these operators will gain a better understanding of their systems by going through the ranking process. Ranking the risks is almost inherent in the other requirements and should not impose an additional burden on these operators. PHMSA has added an element to rank risks to the requirements applicable to MM/LPG systems. b. MM/LPG should be subject to limited IM requirements. The Indiana Utility Regulatory Commission does not agree that MM/ LPG should be subject to the same requirements as other operators. Indiana commented that although there are reasons that master meter operators could be perceived as posing higher risk (e.g., lack of expertise/resources, distributing gas is not primary business, high population density), there has been no record of serious incidents at master meters in Indiana. They stated that these operators struggle to comply with existing rules and will have limited ability to analyze risks, even if the computer program APGA is developing (Simple, Handy, Risk-based, Integrity Management Program--SHRIMP) is available. Indiana suggested we should either exclude master meter operators from this rule or subject them to more limited requirements and allow them to [[Page 63913]] spend their limited resources achieving compliance with existing regulations. While not supporting total exclusion, Missouri and New Hampshire state regulators supported limited requirements for MM/LPG. AZCC commented that the rule should be prescriptive and simple for master meter and small LPG operators, since these operators have limited capability, can be easily overwhelmed and may, if that happens, do nothing. The New Mexico Public Regulation Commission (NMPRC) supported excluding MM/LPG from administrative requirements of the proposed rule. Iowa did not take a position on limiting requirements; however, Iowa and a large operator suggested that evaluation and prioritization of risks should not be excluded for MM/LPG. They see this as a critical step, and not particularly burdensome. PHMSA response: While PHMSA agrees that there are some ``large'' MM operators, most of them are very small. Unlike the large/small LPG operator distinction, which exists in current regulations, all MM operators are treated the same, irrespective of size. Therefore, in this final rule, all MM are subject to the limited IM requirements. The final rule imposes requirements similar to those for other operators but with more limited requirements for documentation, consistent with how these operators are treated in other regulations. They will not be required to report performance measures as they do not file annual reports.\4\ Although these requirements are similar to those applicable to other operators, we have presented them separately, emphasizing that these programs should reflect the simplicity of the pipelines. --------------------------------------------------------------------------- \4\ Operators of LPG systems serving more than 100 customers are required to file annual reports. --------------------------------------------------------------------------- Some comments in response to the NPRM and comments made during earlier stakeholder discussions have disagreed with PHMSA's contention that MM/LPG operators pose less risk. Risk is generally considered to be the product of the likelihood of adverse events and their consequences. Determining risk thus requires knowledge of how often events occur and the consequences they produce. MM/LPG operators are not required to submit written incident reports. They are, however, required to make telephonic reports.\5\ Events with serious consequences (e.g., death or serious injury) are also likely to be reported in local news and thus to come to the attention of regulatory authorities. PHMSA therefore believes it is unlikely a large number of significant events have occurred on MM/LPG systems that are not reflected in incident data. That data includes few serious incidents on MM/LPG systems, supporting PHMSA's contention that the risk from these systems, while not zero, is relatively low. Indiana's comments about the dearth of serious accidents in the incident record are consistent with PHMSA's understanding of the risk of these systems. --------------------------------------------------------------------------- \5\ 49 Code of Federal Regulations, section 191.5. --------------------------------------------------------------------------- c. MM/LPG should not be subject to IM requirements. The National Propane Gas Association (NPGA) suggested that LPG operators should be exempt entirely. NPGA sees no perceived benefit from compliance with the proposed requirements. They noted that LPG systems are very small, that they generally include pipe runs measured in feet vs. miles, and that the total quantity of gas that could be released in an accident is limited by the capacity of the supply tanks, a limitation not shared with natural gas systems. NPGA maintained that their members are already sufficiently regulated, mostly by states and through the incorporation of NFPA Standard 58 (NFPA-58) into Part 192 by reference. They believe that NFPA-58 mirrors the requirements of Part 192 and the proposed rule and noted that the standard is already recognized as the primary governing standard in Sec. 192.11(c) which states that the standard prevails in the event of a conflict between its provisions and Part 192. NPGA also suggested that applying this rule to LPG operators could have unintended consequences. In a competitive environment to reduce costs, operators could break up their systems to fall outside of regulation, thus removing safety oversight completely. PHMSA response: In the NPRM we proposed a simpler set of IM requirements for MM/LPG operators, but we asked if these operators should be completely excluded from IM requirements. The bulk of comments supported limited requirements but opposed excluding these operators, arguing that simple pipelines would need only simple IM plans. In the final rule, PHMSA has not excluded these operators. LPG presents unique hazards; accordingly, PHMSA believes pipeline safety will be enhanced by larger LPG operators engaging in more robust integrity management activities. As discussed above, large LPG operators are subject to the full IM requirements in the final rule, including the administrative requirements. Because of the physical nature of LPG and the safety risks it presents, PHMSA is not persuaded that small LPG operators should be exempted. Furthermore, NFPA Standard 58 does not ``mirror'' the integrity management requirements in this rule and does not adequately address the safety measures provided by this final rule. IM requirements will complement NFPA-58. d. Limitations for small gas distribution operators (other than MM/ LPG). A consultant suggested that distribution IM should be limited to large operators at this time. He noted that the PIPES Act does not mandate such requirements for small operators and suggested that a phased approach would be prudent. He believes that small operators do not have the personnel or background to implement these requirements and that the associated costs will likely exceed the benefits. He noted that the risk from third-party damage on such systems is small, as operators' personnel see most of the system daily. He supported exclusion for small operators similar to that proposed for MM/LPG and suggested that PHMSA collect additional data to see if additional requirements are needed for these operators. A large operator also supported limited requirements for small operators, and would include the number of customers or mileage as a threshold criterion. The Washington Citizens Committee on Pipeline Safety commented that the number of services should not be used alone to delineate small systems. They suggested that the type and uniformity of material, system complexity, geographic spread, and other risk factors be considered as well. APGA suggested that criteria defining a small system should not include limitation to one pressure district and should not limit the type of appurtenances or equipment. APGA commented that these differences do not affect risk. Small distribution operators already file annual reports, so APGA believes that extending the proposed limitations for MM/LPG would have no value for other small operators. NMPRC would exclude small operators from the administrative requirements of the proposed rule based on the number of customers or staff. NMPRC concluded that DIMP principles would be beneficial for these operators but that the associated administrative burden is too great. Missouri would extend all of the MM/LPG limited requirements to small operators. PHMSA response: PHMSA has not limited this rule to large operators. As [[Page 63914]] noted in the NPRM, there is no established threshold to distinguish between large and small operators. In addition, the PIPES Act did not differentiate between large and small distribution operators. The PIPES Act requires, ``the Secretary shall prescribe minimum standards for integrity management programs for distribution pipelines.'' \6\ We received few comments regarding how such a threshold might be established. --------------------------------------------------------------------------- \6\ 49 United States Code, section 60109(e)(1). --------------------------------------------------------------------------- Rather than delineating explicit thresholds based on operator size, PHMSA expects that operators with small systems will need only simplified plans. Operators will be able to scale their programs according to the complexity of their distribution systems. For example, APGA's SHRIMP program will be available to assist small operators in developing their IM plans. e. Limitations for other operators. One operator suggested that limited requirements should also be established for ``circumstantial'' or ``incidental'' operators. This operator is a large company operating hazardous liquid pipelines, but operates a single gas service line from a local distribution company main to a flare at a petroleum barge dock. The operator believes it would be burdensome to have a distribution IM plan for this single service line. A consultant and GPTC also suggested that landfill gas operators should be treated like MM/LPG, since their systems are also small and pose limited risk. New Hampshire recommended that operators of conventional distribution systems that also operate LPG should be allowed to use a single plan for both. One operator suggested that LDC operators that also operate MM/LPG should be allowed to use a single DIMP plan for both. PHMSA response: As MM/LPG operators have not been excluded from IM requirements, we see no compelling reason to exclude these other ``small'' operators. PHMSA considers that the analysis of a small, simple system should be relatively straightforward and should result in a basic IM plan. PHMSA notes the commenter operating a single service line to a flare stack may be considered a large volume customer as long as the service line is not on public property. This final rule does not apply to in-plant piping to a large volume customer. Companies that conclude that compliance with a rule would be overly burdensome due to unique circumstances may have the option to apply for a waiver (or special permit), as permitted by the applicable regulatory oversight authority. The rule does not require that operators of conventional distribution systems that also operate LPG have separate IM plans or that operators of both MM and LPG systems have separate plans for each. We expect that plans developed for their conventional pipelines in response to the other requirements of subpart P should also satisfy Sec. 192.1015. PHMSA agrees that operators with multiple ``systems'' may benefit from having a single IM plan. However, it is also possible that operators who own multiple systems may operate them separately and may desire separate IM plans. Under the final rule, operators will have the flexibility to treat multiple systems under a common plan, or to address them separately. Comment Topic 8: Transmission lines operated by distribution operators. Many industry commenters suggested that piping operated by distribution operators but which is classified as transmission (mostly because it operates at greater than 20% SMYS) should be included in a distribution IM plan rather than in a separate transmission IM plan. These commenters suggested that this could be done in this rule or by changing the definition of a transmission line. Commenters explained that this ``transmission'' piping is usually operated as an integral part of the distribution system, and that it would be more efficient to treat it under distribution IM than under a separate transmission IM plan. Several commenters recognized that additional rulemaking may be needed to accomplish this change. PHMSA response: PHMSA has made no change in response to these comments. The NPRM did not address changing the definition of transmission pipeline; therefore, such an action is outside the scope of this rulemaking. The transmission IM regulations already provide for alternative treatment of low-stress transmission pipeline ( Reductions in the consequences of reportable incidents Reductions in the consequences of non-reportable incidents A reduction in the probability of a major catastrophic incident Reductions in lost natural gas Reductions in emergency response costs Reductions in evacuations Reductions in dig-ins impacting non-gas underground facilities The end of the existing EFV notification requirement The costs of the final rule are estimated to be $130 million in the first year and $101 million in each subsequent year. Those costs cover: Development of an IM program Implementation of the IM program (data acquisition and analysis) Mitigation of risks (leak management, excess flow valve installation and other) Reporting to PHMSA and State Regulators Recordkeeping Management of the IM program. The Regulatory Impact Analyses (RIA) finds that the rule is not expected to adversely affect the economy or the environment. The analysis finds that, for those costs and benefits that can be quantified, the present value of net benefits is expected to be between $21 million and $1.6 billion over a 50-year period after all of the requirements are implemented. Furthermore, the rule is expected yield positive net benefits if it results in eliminating only approximately 12.2 percent of the societal costs the first year, and about 9.5 percent in subsequent years. C. Regulatory Flexibility Act Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether a rulemaking would have a significant effect on a substantial number of small entities. The IM program requirements in this rule apply to gas distribution pipeline operators and require operators of gas distribution pipelines to develop and implement IM plans that will better assure the integrity of their pipeline systems. Many gas distribution pipeline operators meet the Small Business Administration's small business definition of 500 or fewer employees for natural gas distribution operators under North American Industry Classification System (NAICS) 221210. PHMSA estimates that the rule will affect approximately 9,090 small operators. These small operators can be separated into two categories: (1) Local gas distribution utilities with 12,000 or fewer services and (2) master meter and LPG systems. PHMSA estimates there are 1,090 small operators among the local gas distribution utilities with 12,000 or fewer services and approximately 8,000 master meter and LPG systems, all of which are small. Furthermore, PHMSA estimates the rule will cost each of the 1,090 small operators and the 52 LPG operators serving 100 or more customers from a single source, on average, approximately $33,600 in the first year and $15,400 in each subsequent year. PHMSA also estimates that the rule will cost each of the 8,000 master meter and small LPG systems, on average, approximately $2,900 in the first year and $1,100 in each subsequent year. PHMSA does not have information on the operators' revenues and cannot estimate the economic impact the costs will have. The costs associated with the rule may be significant for at least some of the small entities, if the costs exceed 1 percent of the revenues. Therefore, PHMSA believes that the rule could result in a significant adverse economic impact for some of the smallest affected entities. PHMSA has minimized costs for these small operators. As mentioned earlier, small operators' IM programs will be subject to more limited documentation requirements. PHMSA is also providing guidance for small operators. Additionally, industry is undertaking a number of initiatives that will help small entities comply with the proposed rule, including the preparation of guidance materials and a model IM program for distribution pipeline operators. D. Paperwork Reduction Act The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) addresses the collection of information by the Federal government from individuals, small businesses and state and local governments and seeks to minimize the burdens such information collection requirements might impose. A collection of information includes providing answers to identical questions posed to, or identical reporting or record-keeping requirements imposed on ten or more persons, other than agencies, instrumentalities, or employees of the United States. In accordance with the requirements of the Paperwork Reduction Act, agencies may not conduct or sponsor, and the respondent is not required to respond to, an information collection unless it displays a currently valid Office of Management and Budget (OMB) control number. This rule requires operators to report four distribution integrity management program (DIMP) performance measures in the annual report (Incident and Annual Reports for Gas Pipeline Operators. OMB Control Number: 2137-0522). All data required under this rule to be reported will be reported via the annual report. One of the measures required to be reported--all leaks repaired, by cause--has historically been required as part of annual reports. The other information to be reported will require modifications to the annual report form. Therefore, PHMSA is also using this rulemaking as a 60-day notice to revise the annual report information collection, OMB Control Number 2137-0522. PHMSA seeks comment on the proposed modified annual report form, which is available in the docket for this rulemaking. In addition, the rule also requires operators to report, as part of the annual report, detailed information regarding compression coupling failures. PHMSA has created a compression coupling failure addendum to be submitted with the annual report form, as needed. PHMSA also seeks comment on the proposed compression coupling failure addendum form. This form will also be part of the revised 2137-0522 information collection and is available in the docket for this rulemaking. [[Page 63933]] PHMSA estimates that the additional average time required for completing the annual report, beyond the time that gas distribution operators are already expending, is 6 hours per year per operator. This results in a burden increase of 8,058 hours per year for all 1,343 operators that have to comply with the annual report requirements. The required information can be reported electronically. Operators are permitted to keep records in any retrievable form. They may use the latest information technology to reduce the additional information- collection burden. In addition to the reporting requirements, this final rule requires each affected operator to develop and maintain a written integrity management plan, which includes initial plan development, recordkeeping and updates. These non-reporting requirements are covered by Integrity Management Program for Gas Distribution Pipelines, OMB Control Number: 2137-0625. OMB assigned Control Number 2137-0625 to the information collection but withheld approval pending publication of this Final Rule, which addresses comments to the Notice. This Final Rule serves as a 30-day notice for the information collection, and PHMSA will forward an information collection package for OMB review concurrent with publication of this final rule. Each operator, other than master meter operators and small LPG operators, must also collect and record one other specified performance measure and any other performance measures unique to the operator's pipeline that are needed to evaluate the effectiveness of the integrity management program. PHMSA estimates these tasks will require an additional 2,289 hours for all 9,343 operators. An explanation of all burden hour estimates is contained in the Paperwork Reduction Act Supporting Statement and the Regulatory Impact Analysis (RIA) available in the docket for this rulemaking. E. Executive Order 13084 This final rule has been analyzed under principles and criteria contained in Executive Order 13084 (``Consultation and Coordination with Indian Tribal Governments''). Because this rule does not significantly or uniquely affect communities of Indian tribal governments and does not impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13084 do not apply. F. Executive Order 13132 PHMSA analyzed this final rule under the principles and criteria contained in Executive Order 13132 (Federalism). PHMSA issues pipeline safety regulations applicable to interstate and intrastate pipelines. The requirements in this rule apply to operators of distribution pipeline systems, primarily intrastate pipeline systems. Under 49 U.S.C. 60105, PHMSA cedes authority to enforce safety standards on intrastate pipeline facilities to a certified state authority. Thus, state pipeline safety regulatory agencies will be the primary enforcer of these safety requirements. Although some states have additional requirements that address IM issues, no state requires its distribution operators to have comprehensive IM programs similar to that required by this rule. Under 49 U.S.C. 60107, PHMSA provides grant money to participating states to carry out their pipeline safety enforcement programs. Although some states choose not to participate in the pipeline safety grant program, every state has the option to participate. This grant money is used to defray added safety program costs incurred by enforcing the requirements. We expect to increase money available to help states. PHMSA has concluded this rule does not include any regulation that: (1) Has substantial direct effects on states, relationships between the national government and the states, or distribution of power and responsibilities among various levels of government; (2) imposes substantial direct compliance costs on states and local governments; or (3) preempts state law. Therefore, the consultation and funding requirements of Executive Order 13132 (64 FR 43255; August 10, 1999) do not apply. This rule preempts any currently established state requirements in this area. States have the ability to augment pipeline safety requirements for pipelines, but are not able to approve safety requirements less stringent than those contained within this rule. Although the consultation requirements do not apply, the states have played an integral role in helping develop these requirements. State pipeline safety regulatory agencies participated in the stakeholder groups that helped develop the findings on which this rule is based and provided guidance through NARUC in the form of a resolution. PHMSA action is consistent with this resolution. G. Executive Order 13211 This final rule is not a ``significant energy action'' under Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use). It is not likely to have a significant adverse effect on supply, distribution, or energy use. Further, the Office of Information and Regulatory Affairs has not designated this rule as a significant energy action. H. Unfunded Mandates PHMSA estimates that this final rule does impose an unfunded mandate under the 1995 Unfunded Mandates Reform Act (UMRA). PHMSA estimates the rule to cost operators $155.1 million in the first year of the regulations, which is higher than the $100 million threshold (adjusted for inflation, currently estimated to be $141.3 million) in any one year. The Regulatory Impact Analysis performed under EO 12866 requirements also meets the analytical requirements under UMRA, and PHMSA has concluded the approach taken in this regulation is the least burdensome alternative for achieving our rule's objectives. I. National Environmental Policy Act PHMSA analyzed this final rule in accordance with section 102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), the Council on Environmental Quality regulations (40 CFR 1500-1508), and DOT Order 5610.1C, and has determined that this action will not significantly affect the quality of the human environment. PHMSA conducted an Environmental Assessment on the NPRM and did not receive any comment on the preliminary analysis. The Environmental Assessment is available for review in the Docket. List of Subjects in 49 CFR Part 192 Integrity management, Pipeline safety, Reporting and recordkeeping requirements. 0 In consideration of the foregoing, PHMSA is amending Part 192 of Title 49 of the Code of Federal Regulations as follows: PART 192 TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS 0 1. The authority citation for part 192 continues to read as follows: Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, 60116, 60118, and 60137; and 49 CFR 1.53. [[Page 63934]] 0 2. Section 192.383 is revised to read as follows: Sec. 192.383 Excess flow valve installation. 0 (a) Definitions. As used in this section: Replaced service line means a natural gas service line where the fitting that connects the service line to the main is replaced or the piping connected to this fitting is replaced. Service line serving single-family residence means a natural gas service line that begins at the fitting that connects the service line to the main and serves only one single-family residence. (b) Installation required. An excess flow valve (EFV) installation must comply with the performance standards in Sec. 192.381. The operator must install an EFV on any new or replaced service line serving a single-family residence after February 2, 2010, unless one or more of the following conditions is present: (1) The service line does not operate at a pressure of 10 psig or greater throughout the year; (2) The operator has prior experience with contaminants in the gas stream that could interfere with the EFV's operation or cause loss of service to a residence; (3) An EFV could interfere with necessary operation or maintenance activities, such as blowing liquids from the line; or (4) An EFV meeting performance standards in Sec. 192.381 is not commercially available to the operator. (c) Reporting. Each operator must, on an annual basis, report the number of EFVs installed pursuant to this section as part of the annual report required by Sec. 191.11. 0 3. In Part 192, a new subpart P is added to read as follows: Subpart P--Gas Distribution Pipeline Integrity Management (IM) Sec. 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 required elements of an integrity management 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 of this part? 192.1015 What must a master meter or small liquefied petroleum gas (LPG) operator do to implement this subpart? Subpart P--Gas Distribution Pipeline Integrity Management (IM) Sec. 192.1001 What definitions apply to this subpart? The following definitions apply to this subpart: Excavation Damage means any impact that results in the need to repair or replace an underground facility due to a weakening, or the partial or complete destruction, of the facility, including, but not limited to, the protective coating, lateral support, cathodic protection or the housing for the line device or facility. Hazardous Leak means a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous. Integrity Management Plan or IM Plan means a written explanation of the mechanisms or procedures the operator will use to implement its integrity management program and to ensure compliance with this subpart. Integrity Management Program or IM Program means an overall approach by an operator to ensure the integrity of its gas distribution system. Small LPG Operator means an operator of a liquefied petroleum gas (LPG) distribution pipeline that serves fewer than 100 customers from a single source. Sec. 192.1003 What do the regulations in this subpart cover? General. This subpart prescribes minimum requirements for an IM program for any gas distribution pipeline covered under this part, including liquefied petroleum gas systems. A gas distribution operator, other than a master meter operator or a small LPG operator, must follow the requirements in Sec. Sec. 192.1005-192.1013 of this subpart. A master meter operator or small LPG operator of a gas distribution pipeline must follow the requirements in Sec. 192.1015 of this subpart. Sec. 192.1005 What must a gas distribution operator (other than a master meter or small LPG operator) do to implement this subpart? No later than August 2, 2011 a gas distribution operator must develop and implement an integrity management program that includes a written integrity management plan as specified in Sec. 192.1007. Sec. 192.1007 What are the required elements of an integrity management plan? A written integrity management plan must contain procedures for developing and implementing the following elements: (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) Identify 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 compression coupling), equipment failure, incorrect operation, and other concerns that could threaten the integrity of its pipeline. An operator must consider reasonably available information to identify existing 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 [[Page 63935]] likely would be effective in reducing risk. (d) Identify 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 Sec. 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 Sec. 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 re-evaluation 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)(1)(i) through (e)(1)(iv) of this section, as part of the annual report required by Sec. 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. Sec. 192.1009 What must an operator report when compression couplings fail? Each operator must report, on an annual basis, information related to failure of compression couplings, excluding those that result only in non-hazardous leaks, as part of the annual report required by Sec. 191.11 beginning with the report submitted March 15, 2011. This information must include, at a minimum, location of the failure in the system, nominal pipe size, material type, nature of failure including any contribution of local pipeline environment, coupling manufacturer, lot number and date of manufacture, and other information that can be found in markings on the failed coupling. An operator also must report this information to the state pipeline safety authority if a state exercises jurisdiction over the operator's pipeline. Sec. 192.1011 What records must an operator keep? An operator must maintain records demonstrating compliance with the requirements of this subpart for at least 10 years. The records must include copies of superseded integrity management plans developed under this subpart. Sec. 192.1013 When may an operator deviate from required periodic inspections under this part? (a) An operator may propose to reduce the frequency of periodic inspections and tests required in this part on the basis of the engineering analysis and risk assessment required by this subpart. (b) An operator must submit its proposal to the PHMSA Associate Administrator for Pipeline Safety or, in the case of an intrastate pipeline facility regulated by the State, the appropriate State agency. The applicable oversight agency may accept the proposal on its own authority, with or without conditions and limitations, on a showing that the operator's proposal, which includes the adjusted interval, will provide an equal or greater overall level of safety. (c) An operator may implement an approved reduction in the frequency of a periodic inspection or test only where the operator has developed and implemented an integrity management program that provides an equal or improved overall level of safety despite the reduced frequency of periodic inspections. Sec. 192.1015 What must a master meter or small liquefied petroleum gas (LPG) operator do to implement this subpart? (a) General. No later than August 2, 2011 the operator of a master meter system or a small LPG operator must develop and implement an IM program that includes a written IM plan as specified in paragraph (b) of this section. The IM program for these pipelines should reflect the relative simplicity of these types of pipelines. (b) Elements. A written integrity management plan must address, at a minimum, the following elements: (1) Knowledge. The operator must demonstrate knowledge of its pipeline, which, to the extent known, should include the approximate location and material of its pipeline. The operator must identify additional information needed and provide a plan for gaining knowledge over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities). (2) Identify threats. The operator must consider, at minimum, the following categories of threats (existing and potential): Corrosion, natural forces, excavation damage, other outside force damage, material or weld failure, equipment failure, and incorrect operation. (3) Rank risks. The operator must evaluate the risks to its pipeline and estimate the relative importance of each identified threat. (4) Identify and implement measures to mitigate risks. The operator must determine and implement measures designed to reduce the risks from failure of its pipeline. (5) Measure performance, monitor results, and evaluate effectiveness. The operator must monitor, as a performance measure, the number of leaks eliminated or repaired on its pipeline and their causes. (6) Periodic evaluation and improvement. The operator must determine the appropriate period for conducting IM program evaluations based on the complexity of its pipeline and changes in factors affecting the risk of failure. An operator must re-evaluate its entire program at least every five years. The operator must consider the results of the performance monitoring in these evaluations. (c) Records. The operator must maintain, for a period of at least 10 years, the following records: (1) A written IM plan in accordance with this section, including superseded IM plans; (2) Documents supporting threat identification; and (3) Documents showing the location and material of all piping and appurtenances that are installed after the effective date of the operator's IM program and, to the extent known, the location and material of all pipe and [[Page 63936]] appurtenances that were existing on the effective date of the operator's program. Issued in Washington, DC on November 20, 2009 under Authority delegated in Part 1. Cynthia L. Quarterman, Administrator. [FR Doc. E9-28467 Filed 12-3-09; 8:45 am] BILLING CODE 4910-60-P

## Provenance

- Official: Yes
- Source: <https://www.federalregister.gov/documents/2009/12/04/E9-28467/pipeline-safety-integrity-management-program-for-gas-distribution-pipelines>
- Source ID: `federal-register`
- SHA-256: `a3d9feb82d6eea38e2b99106150dffb344b996ec9400f64600e99bb72533688b`
- Retrieved: 2026-08-20T06:04:51.294Z
- Exported: 2026-08-24T12:34:03.055Z
- Document slug: `federal-register-e9-28467`

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