Daily Rules, Proposed Rules, and Notices of the Federal Government
This final rule addresses statutory mandates and recommendations from the DOT's Office of the Inspector General (OIG) and stakeholder groups.
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
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.
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.
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.
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:
A discussion of each comment topic and PHMSA's response to each follows:
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
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.
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 § 192.1009, which would have required reporting of “each material failure of plastic pipe (including fittings,
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.
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.
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
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.
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 (
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 (
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, with1
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.
AGA's comment is incorrect. Congress allowed 10 years for gas transmission operators to complete baseline
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.
Several commenters addressed specific issues associated with the structure of the rule and language in proposed § 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.
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.
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.
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 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.
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 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.
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 (OM) 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.
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 OM 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.
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
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.
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.
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.
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 (
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.
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.
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.
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 § 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.
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.
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.
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 § 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.
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.
The transmission IM regulations already provide for alternative treatment of low-stress transmission pipeline (30% SMYS)
NAPSR, APGA, and a number of operators objected to the proposed requirement that all operators must enhance their damage prevention programs (proposed § 192.1007(d)) because the requirement is open-ended. They suggested that § 192.614, which requires such programs, should be revised if current programs are deemed inadequate.
A consultant suggested that leak management requirements should be included in § 192.723 and damage prevention requirements in § 192.614. He generalized this comment by noting that PHMSA should avoid having two regulations that address the same thing. He considers IM as an extension of all of Part 192, and believes that proposed Subpar