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Information Collection

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AGENCY:

Pipeline and Hazardous Materials Safety Administration.

ACTION:

Request for public comments and OMB approval of existing information collection.

SUMMARY:

On September 4, 2008, as required by the Paperwork Reduction Act of 1995, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a notice in the Federal Register of its intent to revise the agency's standardized forms for reporting pipeline incidents and accidents. PHMSA later extended the time for responding to that notice until December 12, 2008, and received timely comments from several pipeline operators, five trade associations representing pipeline operators, the association representing State pipeline safety regulators, two State pipeline regulatory agencies, and one public interest group. PHMSA is publishing this notice to respond to comments, provide the public with an additional 30 days to comment on the proposed revisions to the incident and accident report forms, including the form instructions, and announce that the revised Information Collections will be submitted to the Office of Management and Budget (OMB) for approval.

DATES:

Comments on this notice must be received by September 16, 2009 to be assured of consideration.

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FOR FURTHER INFORMATION CONTACT:

Roger Little by telephone at 202-366-4569, by fax at 202-366-4566, by e-mail at Roger.Little@dot.gov, or by mail at U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., PHP-10, Washington, DC 20590-0001.

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ADDRESSES:

You may submit comments identified by the docket number PHMSA-2008-0211 by any of the following methods:

  • Federal eRulemaking Portal: http://www.regulations.gov. Follow the online instructions for submitting comments.
  • Fax: 1-202-395-6566
  • Mail: Office of Information and Regulatory Affairs (OIRA), Office of Management and Budget (OMB), 726 Jackson Place, NW., Washington, DC 20503, ATTN: Desk Officer for Department of Transportation (DOT).
  • E-mail: Office of Information and Regulatory Affairs (OIRA), Office of Management and Budget, at the following address: oira_submissions@omb.eop.gov.

Requests for a copy of the information collection should be directed to Roger Little by telephone at 202-366-4569, by fax at 202-366-4566, by e-mail at Roger.Little@dot.gov, or by mail at U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., PHP-10, Washington, DC 20590-0001.

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SUPPLEMENTARY INFORMATION:

Section 1320.8(d), Title 5, Code of Federal Regulations requires PHMSA to provide interested members of the public and affected agencies an opportunity to comment on information collection and recordkeeping requests. This notice identifies revised information collection requests that PHMSA will be submitting to OMB for approval. These information collections are contained in the pipeline safety regulations, 49 CFR parts 190-199. PHMSA has revised burden estimates, where appropriate, to reflect current reporting levels or adjustments based on changes in proposed or final rules published since the information collections were last approved. The following information is provided for each information collection: (1) Title of the information collection; (2) OMB control number; (3) type of request; (4) abstract of the information collection activity; (5) description of affected public; (6) estimate of total annual reporting and recordkeeping burden; and (7) frequency of collection. PHMSA will request a three-year term of approval for each information collection activity. The comments are summarized and addressed below as specified in the following outline:

I. Background

II. Summary of Comments

A. Incident Report Form PHMSA F 7100.1, Gas Distribution Systems (Impacted Information Collection: OMB Control No. 2137-0522)

B. Incident Report Form PHMSA F 7100.2, Gas Transmission and Gathering Systems (Impacted Information Collection: OMB Control No. 2137-0522)

C. Incident Report Form PHMSA F 7000-1, Accident Report—Hazardous Liquid Pipeline Systems (Impacted Information Collection: OMB Control No. 2137-0047)

III. Proposed Information Collection Revisions and Request for Comments

I. Background

The Pipeline and Hazardous Materials Safety Administration (PHMSA) requires that an operator of a covered pipeline facility file a written report within 30 days of certain adverse events, defined by regulation as either an accident or incident, 49 CFR 191.1-191.27, 195.48-195.63 (2008).[1] PHMSA further requires that those reports be submitted to the agency on one of three standardized forms, PHMSA Form F 7100.1, Incident Report—Gas Distribution Pipelines, PHMSA Form F 7100.2, Incident Report—Gas Transmission and Gathering Systems, and PHMSA Form F 7000-1—Accident Report for Hazardous Liquid Pipeline Systems. PHMSA uses the information collected from these forms (1) to identify trends in the occurrence of safety-related problems, (2) to appropriately target its performance of risk-based inspections, and (3) to assess the overall efficacy of its regulatory program.

PHMSA published a Federal Register notice on September 4, 2008 (73 FR 51697) inviting public comment on a proposal to revise PHMSA Forms F 7100.1, F 7100.2, and F 7000-1. PHMSA stated that the proposed revisions were needed “to make the information collected more useful to” all those concerned with pipeline safety and to provide additional, and in some instances more detailed, data for use in the development and enforcement of its risk-based regulatory regime. PHMSA published a subsequent Federal Register notice on October 30, 2008 (73 FR 64661) to extend the comment period to December 12, 2008.

II. Summary of Comments

During the three-month response period, the following groups provided PHMSA with comments on the proposal outlined in the September 2008 Federal Register notice:

Five industry trade associations—American Gas Association (AGA), American Public Gas Association (APGA), American Petroleum Institute (API), American Oil Pipelines Association (AOPL), and Interstate Natural Gas Association of America (INGAA).

The National Association of State Pipeline Safety Representatives (NAPSR) and two State pipeline regulatory agencies—Iowa Utilities Board (IUB) and Missouri Public Service Commission (MOPSC).

Nine pipeline operators—Southern California Gas Company and San Diego Gas & Electric (SoCal/SDG&E), MidAmerican Energy Company (MidAmerican), Northern Illinois Gas Company d/b/a Nicor Gas Company (Nicor), Atmos Energy Corporation Start Printed Page 41497(Atmos), Southwest Gas Corporation (Southwest), El Paso Pipeline Group (EPPG), Columbia Gas Transmission (CGT), Panhandle Energy (Panhandle), and Paiute Pipeline (Paiute).

The Pipeline Safety Trust—A summary of those comments and PHMSA's responses is provided below for each of the three proposed incident report forms and related instructions.

A. Incident Report Form PHMSA F 7100.1—Gas Distribution Systems (Impacted Information Collection: OMB 2137-0522)

General Comments

Increase in requested information: AGA and APGA noted that the proposed changes would increase the length of the form from 3 to 10 pages. AGA and APGA cautioned that while such an increase was not objectionable per se, PHMSA should ensure the relevance of any additional information being collected.

PHMSA response: The increase in the total number of pages in the revised PHSMA Form F 7100.1 does not accurately reflect the information collection burden that will be placed on operators. Most of the additional pages are dedicated to Part F, Cause Information. Part F is subdivided into 8 separate categories, and an operator is only required to complete the section that relates to the primary cause of the incident. In other words, an operator will only need to answer the questions presented on pages 6 and 7 if corrosion caused the incident, on page 7 if natural force damage caused the incident and, on page 8 and 9 if excavation damage caused the incident. Similarly, depending on the location of the incident, only the Onshore or Offshore selection will need to be completed.

Moreover, the vast majority of operators elect to use PHMSA's online incident reporting form, a tool that utilizes smart navigation and formatting to filter out irrelevant sections, thereby decreasing the actual numbers of pages that must be viewed by an operator. Thus, it is misleading to suggest that the increase in the total number of pages used in the revised form is indicative of an unduly burdensome information collection.

Nevertheless, PHMSA acknowledges that the revised form will collect new, and in some instances more detailed, information. However, PHMSA has determined that the collection of such information is justified by the agency's need to identify trends in safety-related problems, to appropriately target its performance of risk-based inspections, and to assess the overall efficacy of its pipeline-safety regime.

Rely more on narrative: APGA noted that prior studies show that narrative descriptions are a better source of data on the cause of reported incidents and suggested that PHMSA should provide more guidance with respect to the information sought in that portion of the revised form, rather than increasing the number of questions in others areas.

PHMSA response: PHMSA agrees with APGA's comment regarding the successful use of narrative descriptions in identifying the cause of reported incidents in prior studies. However, those studies required the investment of substantial time and effort into data extraction, and the lack of uniformity in the information collected meant that inferences often had to be drawn to reach a final conclusion. PHMSA has carefully examined this issue and determined that its incident reporting data collection needs are ill suited to such an approach, i.e., that the information submitted by operators must be presented in a standardized format that can be easily received, stored, and analyzed. The revised form is consistent with that approach.

Report vs. investigation: Many industry stakeholders argued that the revised form seeks to collect more information than is necessary for an adequate incident report. Some even suggested that the new form cannot be completed without conducting a root cause investigation for each incident.

PHMSA response: PHMSA agrees that the proposed revisions are designed to collect new, and in some instances more detailed, data on incidents, but firmly rejects the suggestion that a root cause investigation must be conducted to complete the form. To the contrary, PHMSA is confident that a prudent operator can complete the form in a reasonable amount of time based on the information available at or near the time of the incident. PHMSA also does not agree that the additional effort that may be needed in some cases to complete the revised form is unjustified. While the number of incidents that occur annually has declined in recent years, PHMSA remains committed to reducing the occurrence and mitigating the consequences of these adverse events, and more detailed data is required to support these analyses.

Changes needed in criteria for reporting: A number of commenters suggested that the criteria for a reportable incident should be changed, focusing in particular on the $50,000 threshold for property damage and noting that the combined effects of inflation, escalating property values, and increases in the price of gas require that more and more incidents be reported.

PHMSA response: PHMSA recognizes that the number of reportable incidents will increase with any rise in the cost of gas and property values. However, an incident is defined by regulation, and a rulemaking must be initiated to change that definition. That type of regulatory change is beyond the scope of this information collection request.

Time to file: MidAmerica suggested that additional data and investigation will be required to complete the revised form; therefore, the deadline for its submission to PHMSA should be extended from 30 to 60 days after an incident.

PHMSA response: The 30-day deadline for filing an incident report is set by regulation and can only be changed in a notice-and-comment rulemaking, an action that is beyond the scope of this information collection request. Nonetheless, PHMSA acknowledges that certain information may not be known by an operator within 30 days of an incident, and that is why the regulation allows operators to include additional information in supplemental reports filed after the initial report is submitted.

Relationship to pending rulemakings: Several pipeline operators noted that PHMSA is developing new rules on distribution integrity and control room management and that the revised form requests information on these issues. These operators therefore argued that the proposed revision of the incident reporting form should be deferred until those two rulemakings are completed.

PHMSA response: Congress has mandated PHMSA to use its broad authority to collect information on pipeline facilities, 49 U.S.C. 60117(b)(1)-(2), to obtain specific data from owners and operators on the role of controller fatigue in incidents and accidents. Pipeline Inspection, Protection and Safety Act (PIPES Act) of 2006, Public Law 109-468, section 20, 120 Stat. 3498 (Dec. 29, 2006). However, rather than addressing that mandate in isolation, PHMSA is coordinating its collection of that information with its pending rulemakings on distribution integrity and control room management. Distribution lines are a key part of the nation's pipeline network, and Congress has determined that additional information on the contribution of controller fatigue to the occurrence of incidents and accidents is vital to PHMSA's safety mission. These authorities provide ample support for collecting all of the information sought Start Printed Page 41498in the proposed revision to the incident reporting form without further delay.

Part A, Key Report Information

Question 1 and 2,[2] Operator identification: IUB suggested that a mailing address is still needed for any official correspondence that may be needed in response to an incident. IUB also noted that while PHMSA may have access to an address through its Operator Identification (OPID) system, others seeking to contact the company may not have access to such information.

PHMSA response: PHMSA agrees and has made the suggested change.

Question 4, location of incident: NAPSR suggested that question 4 concerning location of an incident be modified to provide separate lines for entering City and County/Parish and to require that location be reported by GPS coordinates, including identification of the relevant “projection” to better define the latitude and longitude information. IUB also noted that distribution lines may be in unincorporated/undeveloped areas where a street address is not useful to define location and that some other means of describing the location is needed.

PHMSA response: Latitude and longitude were included in this form when it was last revised. This information was not included in the draft revised form, but has been restored. Industry comments on the previous revision expressed concern over requirements to specify a projection, stating that this information would not be available to many distribution pipeline operators and may be confusing. PHMSA elected at that time to omit a requirement that operators specify the projection used. Since PHMSA did not propose such a change in the September 4, 2008, notice, the requirement to report latitude and longitude is being retained as in the previous form, without a need to report projection. PHMSA has made the editorial change suggested by NAPSR to separate City and County/Parish.

Question 7, commodity released: A number of commenters noted that the term “spilled” is inappropriate for natural gas and suggested that it be replaced with “released.” NAPSR noted that natural gas and propane are the only commodities currently transported by gas distribution pipelines and suggested that other commodities listed be deleted. APGA and MidAmerican also noted that the gas distribution pipeline industry does not use the terms “sour” or “wet” to characterize gas carried and suggested that these terms be deleted or defined in the instructions.

PHMSA response: PHMSA agrees and has made the suggested changes.

Question 8, type of system: MidAmerican suggested that the need to distinguish between privately- and municipally-owned systems should be eliminated, since the same regulations are applicable to both.

PHMSA response: Part 192 safety regulations apply to both types of systems. Many outside factors affect private and municipal systems differently, however, and could result in different incident trends. This data is needed to be able to determine if incident trends are different for privately- and municipally-owned systems.

Questions 9 and 10, amount released: Several pipeline operators objected to the need to report separately the volume of commodity released intentionally and unintentionally. They noted that it would be difficult, at best, to prepare these estimates. Atmos also noted that the form should reflect that these quantities are only estimates.

PHMSA response: PHMSA agrees and has revised the form to ask only for an estimate of total commodity released.

Questions 11 and 12, number of fatalities and injuries: A number of pipeline operators suggested that PHMSA delete the category of “Workers working on the Public Easement or near pipeline facility but not associated with this operator or this pipeline facility.” They consider the category confusing and note that the category of “general public” would already account for non-operator personnel. Southwest also suggested that the category of “emergency responders” should be limited to non-operator personnel, since operator employees and contractors are addressed in other categories.

PHMSA response: Utility easements are used for purposes other than gas distribution pipelines. Thus, there may be workers associated with other utilities (e.g., electric, cable television, sewer/water) performing work on the easement. This category of “public” is more likely to be involved in an incident, since they are more likely to be engaged in work that might disturb pipelines in an easement than are other members of the public. PHMSA considers it important to collect this data to be able to determine if common location of utilities is a factor contributing to incident frequency. Similar situations exist for other pipeline types with other pipelines/utilities installed in common rights-of-way, and PHMSA also collects this data for those pipelines. Therefore, PHMSA has retained this category. PHMSA agrees with Southwest that the emergency responder category was intended to apply to responders not employed by the pipeline operator and has modified the form to so indicate.

Question 15, number evacuated: MidAmerican suggested revising this question to seek the estimated number of general public evacuated, if known. They noted that non-operator emergency responders often suggest evacuation and persons self-evacuate and it may not be possible to know how many persons evacuated.

PHMSA response: PHMSA recognizes that this data will be an estimate and may be subject to some uncertainty, but does not consider that changes to the form are needed. PHMSA expects operators to exercise reasonable diligence in estimating the number of people evacuated.

Question 16, elapsed time: NAPSR suggested that this question be revised to collect a time sequence of key events such as when the operator was notified, when operator personnel arrived on site, and when the area was made safe. Other commenters noted that the form and instructions were not consistent for this question.

PHMSA response: PHMSA agrees that a time sequence would provide more useful information and eliminate the need for an operator to make the calculation implicit in the original question—time between becoming aware of the incident and making the area safe. PHMSA has revised this question to a time sequence. PHMSA has implemented this change for the other incident report forms as well.

Part B, Additional Location Information

Question 17, location of system involved: MidAmerican commented that the location of the system is of little importance and suggested that most of this question be deleted. Southwest commented that the location information sought in this question duplicates information to be collected later in the form (section F3, Excavation Damage) and therefore suggested that this question be deleted to avoid duplication. Southwest also questioned the meaning of “bridge crossing,” asking whether that term applied to waterway crossings or to all bridges. They noted that a bridge can cross a road, meaning that two of the available options could be selected. NAPSR suggested changing “right-of-way” to “easement,” as that term is more appropriate for use in Start Printed Page 41499distribution pipelines. Southwest also noted that the terms have different legal connotations.

PHMSA response: PHMSA considers this data important to identify national trends. Excavation activities can be expected to occur more frequently in areas with utility easements, but more data is need to confirm that hypothesis. Similarly, utilities and their contractors should be more knowledgeable about one-call procedures and the need to avoid damage to underground utilities. Data is also needed to confirm that hypothesis and the need for additional regulatory action, if appropriate.

Data on bridge and other types of crossings is needed to determine if such locations are more likely to experience an incident and, if so, the steps that can be taken to mitigate the consequences thereof. In addition, whether a bridge crosses a roadway or a waterway is not as important as the fact that the pipeline must be integrated with or attached to the bridge structure. PHMSA will clarify in the instructions that only one option should be selected.

With regard to duplication, section F3 only applies if the cause of an incident is excavation damage. However, question 17 applies to all incident types. Therefore, the information sought is not unnecessarily duplicative.

PHMSA agrees that “easement” is a more appropriate term for distribution pipelines and has used that term.

Question 18, area of failure: Nicor and Atmos objected to the use of the undefined term “failure” and commented that an incident may result from circumstances outside the control of a pipeline operator, e.g., impact by a non-operator vehicle and not from a “failure” of the pipeline. In commenting on the gas transmission form, INGAA also noted that incidents can result from inappropriate but intentional releases of gas in which a failure does not occur. IUB noted that the options available on the form were not adequate to address many situations. For example, IUB observed that most underground pipelines are simply buried under soil, but that this is not one of the options for selection. Instead, it would need to be reported as “other” and described. IUB considered it inappropriate that reporting of the most common situation should be relegated to “other.” APGA also noted the need for an “under soil” selection. IUB also noted that the options do not address underground valve vaults and questioned the characterization of “in an open ditch” as an above-ground failure.

PHMSA response: The comments questioning the use of the term “failure” relate principally to the issue of liability. PHMSA recognizes in that regard that incidents may be caused by circumstances outside the control of a pipeline operator, and that the operator may not be culpable for their occurrence. However, a failure usually still occurs, i.e., pipe or some appurtenance that is supposed to contain transported gas fails to do so and gas is released. It is important to collect data on where these failures occur in order to be able to identify trends that may indicate a need for additional action, e.g., additional regulations or increased coordination with the other agencies with jurisdiction over the activities that can affect pipelines. Nevertheless, PHMSA recognizes that incidents can result from non-failure releases and has revised the form to avoid the use of the term “failure,” instead referring to “area of incident.” PHMSA will clarify in the instructions that this is to describe the point at which gas was released from the pipeline facility vs. where consequences were realized (e.g., neighboring building in which released gas collected resulting in ignition).

PHMSA agrees with IUB that the options provided on the form did not adequately describe many typical installations, including “under soil.” PHMSA has revised the form to include those installations identified by IUB.

Part C, Additional Facility Information

Question 20, information collected when mains or services are involved: NAPSR suggested that examples be added for pipe specification (e.g., API-5L, ASTM D2513). Several pipeline operators also suggested that the meaning of “pipe specification” was not clear. IUB commented that the original specification may not be known and that “unknown” should therefore be an option. Southwest suggested that the listed coating types be reviewed as they present some likelihood of overlap and confusion. Some pipeline operators also suggested that “unknown” needed to be an option for pipe coating; they also noted that this information was only important for incidents resulting from external corrosion. Some operators suggested that depth of cover is not a parameter of importance, or that it is important only on initial installation. MidAmerican suggested that none of the information sought in this question has much value for distribution pipelines. Several commenters also pointed out that numbering within this question was incorrect.

PHMSA response: PHMSA has adopted NAPSR's suggestion and added examples of pipe specification. PHMSA believes this obviates the need for a definition of the term. PHMSA has also added an option for “unknown” for all of the information, except nominal pipe size.

However, PHMSA rejects the notion that depth of cover is not important. It is true that requirements for depth of cover apply at installation. Nevertheless, inadequate depth of cover could be a factor in why incidents occur. The data that will be collected through this question will enable analyses to determine whether changes in depth of cover requirements or other mitigative actions may be needed. Similarly, PHMSA considers that the other data sought in this question is necessary to evaluate possible trends in incidents. PHMSA does not consider that collecting this information will impose unreasonable burdens, particularly since an option has been provided to indicate “unknown” if the information is not readily discernible.

PHMSA has corrected the numbering.

Question 21, type of release: APGA suggested that overpressure is more appropriately classified as the cause of a failure and should therefore be removed as a type of failure.

PHMSA response: PHMSA agrees and has made the change.

Question 22, material involved: NAPSR suggested adding Cellulose Acetate Butyrate (CAB) as a type of plastic pipe. APGA suggested that more instruction was needed to assure appropriate reporting of polyethylene (PE) and cross-linked PE or, alternatively, that the standard number for the pipe should be reported. Atmos noted that specified minimum yield stress (SMYS) is not an important parameter for distribution piping and suggested that it be deleted. Several commenters noted that standard dimension ratio (SDR) is not applicable to all plastic pipe and suggested that an option to report wall thickness be provided. For PE pipe, Atmos noted that “grade” is not an appropriate concept and Southwest suggested replacing this sub-question with reporting of the Pipe Material Designation Code. Several commenters identified the need to allow “unknown” and “other” as options for the information sought in this question.

PHMSA response: PHMSA agrees and has made the suggested changes. The form has been modified to add the designator PEX for cross-linked polyethylene, which is commonly known by that acronym.

Question 23, year of installation: IUB suggested that the form allow for “unknown,” as operators may not always know the year in which some components of a pipeline were installed.Start Printed Page 41500

PHMSA response: PHMSA agrees and has made the change.

Part D, Additional Consequence Information

Question 24, cost data: MOPSC, Nicor, and Atmos noted that the cost of repair and the cost of emergency response are not required to be considered by 49 CFR 191.3 in determining whether an incident has occurred. They therefore suggested that it is not appropriate to collect this data. Most commenters suggested that cost of emergency response be limited to response costs incurred by the pipeline operator. Costs of outside response agencies are difficult to obtain and are often not directly comparable between jurisdictions. MidAmerican and Southwest questioned the need to estimate separately the cost of gas released intentionally and unintentionally. Several commenters also requested that the form explicitly recognize that the reported costs are expected to be estimates. Southwest asked for guidance concerning what estimated costs are sufficient to submit a “final” report, noting that some repair and restoration costs (e.g., repaving) can be incurred over a significant period of time. MidAmerican suggested that the requirement to report emergency response costs could lead to a need for an administrative procedure to capture costs in real time that could delay emergency response.

PHMSA response: The revision of this form does not change the criteria of an incident as defined in 49 CFR 191.3. Nevertheless, costs are incurred for repairs and for emergency response when most incidents occur. Consideration of these costs helps identify the relative significance of an incident, and PHMSA thus considers it appropriate to collect this data. PHMSA agrees that it would be an unreasonable burden to require operators to estimate the costs incurred by outside emergency response agencies and has limited this factor to costs incurred by the operator for emergency response. PHMSA has eliminated the need to estimate costs separately for intentionally and unintentionally released gas, consistent with the changes discussed above for questions 9 and 10. PHMSA has modified the form to note explicitly that the reported costs are expected to be estimates.

With respect to the question asked by Southwest, PHMSA does not consider it practical to provide definitive guidance for when cost estimates can be considered final. This will vary depending on each particular situation, and inherently requires a judgment on the part of the operator. PHMSA expects that all significant costs associated with an incident will be estimated as part of the initial or a supplemental incident report, regardless of whether those costs are incurred soon after an incident or at some later time. Operator judgments in this regard will be reviewed as part of the regulator's investigation of an incident, and additional supplemental incident reports may be requested if the regulator concludes that significant costs have not been included in reported estimates.

With respect to the potential for delaying emergency response, PHMSA considers that this claim is exaggerated. This form does not require that precise costs be reported. Real-time collection of cost data is neither needed nor required. Operators will be able to estimate costs for emergency response after an event and without affecting response during an incident.

Question 25, customers out of service: SoCal/SDG&E, Nicor, and MidAmerican questioned the need to report this information. They suggested that the number of customers affected by an incident is not related to safety and that the need to report could create a disincentive to shut off services that might be contrary to safety. Nicor noted that outside emergency responders often turn off service to customers regardless of the seriousness of an incident. Southwest suggested that this question be re-phrased to seek total number of “customer accounts” out of service. They note that in the case of master meter accounts, a pipeline operator may not know the number of customers beyond the master meter.

PHMSA response: While subject to some degree of uncertainty, PHMSA has determined that the number of customers placed out of service as a result of an incident is a reasonable and readily available measure that helps to quantify the relative significance of an incident. PHMSA has therefore retained the requirement to report this information. PHMSA has not changed the terminology as suggested by Southwest. PHMSA is concerned that the number of “accounts” could lead to other confusion. PHMSA agrees that what is to be reported is the number of customers served by the pipeline operator, and that in the case of a master meter this would be one; PHMSA does not expect operators to estimate how many additional customers are beyond a master meter that the operator serves.

Part E, Additional Operating Information

Question 26, estimated pressure: In addition to asking for the estimated pressure at the point and time of the incident, IUB suggested asking for the normal operating pressure as distribution systems often operate below their maximum allowable operating pressure (MAOP) and this information could be relevant to safety considerations.

PHMSA response: PHMSA agrees and has added this question.

Question 28, MAOP: MidAmerican commented that this question should be deleted as this parameter is inspected by State utility boards and need not be reported here. Southwest recommended that 49 CFR 192.621 be referenced as another section under which a distribution pipeline MAOP may be established.

PHMSA response: PHMSA understands that the established MAOP is subject to review by State pipeline safety regulators, but considers the information to be relevant to evaluating an incident or to subsequent analysis of incident trends. PHMSA has made the addition suggested by Southwest.

Question 29, how detected: MidAmerican suggested that this question be deleted since an operator may not be aware of how an incident was detected. It may have been reported to the operator by emergency response personnel or others who may not have that information.

PHMSA response: PHMSA has revised this question to ask how the incident was initially identified by the operator. Notification by emergency responders is one of the options provided for selection. Operators need not report how those reporting an incident became aware of it, only how the operator became aware.

Questions 30 and 31, controller involvement: AGA and Southwest suggested that these questions be deleted until the definition of controller was further clarified in the pending rulemaking on control room management. Several other commenters suggested that controller actions were not relevant for distribution pipelines and that the questions should therefore be deleted. AGA suggested adding an option for “NA” for cases where a controller had no involvement and another option to indicate that the extent of controller involvement was still under investigation.

PHMSA response: As previously noted, Congress ordered PHMSA to collect information on the role of controller fatigue in incidents and accidents, and the agency is coordinating the execution of that mandate with its pending rulemaking on control room management. Nevertheless, PHMSA has responded to Start Printed Page 41501the comments received from the various stakeholders by significantly reducing the amount of information sought in this section of the form, much of which PHMSA will obtain through the use of alternative means, including accident investigations. Having taken these steps, PHMSA is confident that it has resolved any past concerns over the information sought in this section. PHMSA has also added options in the controller involvement section for “NA” and result pending further investigation as suggested.

Questions 32 and 33, drug and alcohol testing: AGA and APGA suggested that the number of operator employees and contractors be reported separately rather than together. AGA further suggested that the form make clear that the only contractors to be reported are those engaged by the pipeline operator. Southwest noted that the form implicitly assumes that a drug or alcohol test was required as a result of the incident and suggested that the form be revised to first report whether such a test was required.

PHMSA response: PHMSA agrees and has made the suggested changes. These questions have been modified to ask first if a post-incident drug or alcohol test was required and then separately to report the number of operator employees and operator-employed contractors who failed such tests.

Question 34, operator qualification: AGA commented that whether an incident involved a task covered under operator qualification requirements (i.e., a “covered task”) is a judgment that would be part of an incident investigation rather than a report. Nicor suggested adding “NA” as an option since they did not believe there was a way to indicate that a covered task was not involved.

PHMSA response: PHMSA recognizes that identifying whether a covered task was involved might be part of an incident investigation and not immediately obvious upon occurrence. That does not mean, however, that it is inappropriate to report the information. There are other questions posed on this form that will require some investigation to answer. Collection of this data, including whether a covered task was involved and if employees were qualified, is important to analyzing trends to determine if regulations may be inefficient in preventing incidents. PHMSA notes that Nicor's suggested change is not needed. The form asks if actions that led to an incident were a covered task. If they were not, i.e., if no covered task was involved, then an operator simply reports “no.” PHMSA has moved these questions to Part F, Cause F7—Incorrect Operations, so they only need to be answered for incidents where personnel errors are the principal cause.

Part F, Cause Information

Cause categories: Southwest suggested that this form should be consistent with causes being considered for distribution integrity management under a rulemaking docket that is still open.

PHMSA response: Based in part on the contribution and views of industry stakeholders, including Southwest, the proposed rule on distribution integrity management only incorporates the broad cause categories that are listed in the revised incident reporting form, and those categories are unchanged from the previous version of the form. Thus, the cause categories are consistent with those used in the pending rule on distribution integrity management and the prior versions of this form and are well-known throughout the pipeline safety community. Moreover, the additional information requested in the revised form, including the sub-categories not explicitly included in the proposed integrity management rule, are important for analyzing incident trends. Lastly, PHMSA will address cause categories for the distribution integrity management and the annual report form for distribution systems in a subsequent Federal Register notice and coordinated with the pending distribution integrity management rulemaking. While we do not anticipate any changes to cause categories on incident forms as a result of the pending rulemaking, PHMSA will review the cause categories on the distribution annual report in the course of that rulemaking and align the cause categories with those implemented for incident forms through this Federal Register notice.

Part F, F1—Corrosion Failure

Internal corrosion: The draft form posed a number of questions for incidents caused by external corrosion, but none for those related to internal corrosion. NAPSR suggested information that should be sought for internal-corrosion incidents. This included whether corrosion inhibitors were used, whether the interior was coated or lined with protective coating, whether corrosion coupons were used for monitoring, and an indication of whether the location of the incident was one at which internal corrosion might have been anticipated (e.g., low point, drop out). MOPSC also suggested collecting data about the nature of the location where the failure occurred. Southwest suggested asking if liquids were found in the system.

PHMSA response: PHMSA agrees and has added the questions NAPSR and Southwest suggested.

Cathodic protection: MidAmerican suggested that the question relating to when cathodic protection (CP) was started should be made optional, because this information might not be available for older systems. They also suggested that the information might be of limited use, because it will not be clear whether protection was adequate.

PHMSA response: PHMSA has added an option for “unknown” to address those situations where operators might not know when protection was started for older systems. PHMSA understands that the adequacy of CP could still be questionable, but whether or not CP was provided is an objective data element that is relevant for incident trend analyses. In fact, a report that an external-corrosion incident occurred in a system that was protected by CP from installation could well indicate potential adequacy issues for the CP.

Part F, F2—Natural Force Damage

Temperature: NAPSR suggested creating a separate sub-category for natural or forest fires and eliminating the sub-question regarding these under the temperature sub-cause. Southwest commented favorably on treatment of forest fires under “temperature” but asked if it would apply to fires caused by arson.

PHMSA response: PHMSA agrees that treating forest fires as a sub-category of temperature was inadequate. PHMSA has modified the form to treat incidents caused by outside fires in two places. One is under natural force damage—lightning, as a sub-category indicating a secondary impact such as resulting from nearby fires. The other is under outside force damage (F4) for nearby industrial, man-made, or other non-natural fire/explosion as the primary cause of the failure. Man-made fires, even if forest fires, would be reported under F4.

Part F, F3—Excavation Damage

Several commenters suggested changes to the additional information sought for incidents caused by excavation damage. Among them:

  • Deleting unknown/other as a choice for location, since operators should know the location.
  • Requiring detailed information concerning the one-call notification.
  • Clarifying the information required for utilities in common trenches.
  • Clarifying that the name of excavator is a company name vs. an Start Printed Page 41502individual or deleting the requirement to report the name.
  • Rearranging the form.
  • Adding additional types of markings.
  • Requiring additional information about the interaction between the pipeline operator and those making one-call requests.
  • Eliminating the questions concerning whether the excavator incurred downtime and whether the excavation had been ongoing for more than one month.
  • Deferring to the Common Ground Alliance's Damage Information Reporting Tool (DIRT).
  • Deleting information about circumstances over which the operator had no control.
  • Deleting the question about whether notification of excavation had been received, because excavators are required to notify.
  • Deleting the type of excavator and work performed.
  • Deleting the type of locator.
  • Requiring only mandatory DIRT fields or requiring reporting via DIRT rather than duplicating their reporting requirements.

PHMSA response: The Common Ground Alliance (CGA) is the recognized authority for preventing excavation damage of underground utilities. The CGA has determined the information necessary to evaluate excavation damage trends via its DIRT system. PHMSA has adopted in this form the fields defined within the DIRT system as mandatory. Collecting information on excavation damage consistent with DIRT will allow for thorough analyses to identify trends related to excavation damage. It will also allow comparative analyses to consider information reported to DIRT by other underground utility operators, thereby expanding the database and potentially affording additional insights.

Part F, F4—Other Outside Force Damage

Fire-caused: AGA recommended deleting the sub-category related to events caused by nearby fires. They contend that these events are outside of PHMSA jurisdiction, and that their inclusion in DOT statistics will distort the safety record. In support of their argument, they note that the DOT incident database records 17 such events in 2007 despite hundreds of thousands of fires reported by other Federal agencies. Nicor also suggested that this category be deleted as such events should only be reported if additional damage due to the gas release exceeds reporting criteria. Southwest questioned if this category is appropriate for reporting incidents initiated by fires caused by arson.

PHMSA response: Fires whose causes are unrelated to gas distribution systems can cause situations that are reported as gas distribution incidents. AGA's citation to the 2007 DOT data proves that point. A 2003 analysis of incident data sponsored by PHMSA found that a small, but significant, percentage of reported incidents were such fire-first events. It is important to be able to identify these events when analyzing incident experience, in part to be able to separate them out as incidents that were not under the control of pipeline operators. In fact, many incidents are caused by circumstances not under the control of a pipeline operator and thus outside of PHMSA jurisdiction (e.g., excavation damage). Nevertheless, it is important to be able to characterize correctly the causes of incidents in order to draw appropriate lessons from analyses of incident data. PHMSA agrees that fire-first incidents need not be reported unless reporting criteria in 49 CFR 191.3 are met, but that does not eliminate the need to capture appropriately the data for circumstances in which a report is required. PHMSA has retained this category. As described above, this category would be appropriate for reporting incidents from arson-related fires.

Damage by vehicles: AGA and Nicor recommended eliminating the sub-category for damage by vehicles not engaged in excavation. They note that vehicle accidents happen, that operators would not be culpable, and that collection of this data is thus unnecessary. Nicor and Southwest further noted that there are parameters relevant to a complete understanding of vehicle-impact events that will be unknown to pipeline operators.

PHMSA response: Culpability is not the issue. As with fire-first events, analysis of distribution pipeline incident data has shown that incidents caused by vehicle impacts are a small, but significant, percentage of all incidents. Again, PHMSA is not attempting to regulate the operation of vehicles near pipelines. It is necessary to a complete understanding of the incident experience to be able to identify incidents caused by vehicle impacts. Asking whether a vehicle barrier was in place does not pre-suppose that the absence of such a barrier was a contributing cause to an incident. The presence or absence of such barriers is a factor that can be within the control of a pipeline operator and which could be important to understanding the importance of such protection. It is therefore appropriate to identify whether such barriers were present.

Part F, F5—Pipe, Weld, or Joint Failure

General: MidAmerican commented that this section adds little value for distribution pipelines and should be deleted. Southwest suggested that this section is disorganized and that it should be restructured to ask first questions related to both metal and plastic pipe and then those specific to a type of material.

PHMSA response: PHMSA continues to consider this section important. The greater use of plastic pipe in distribution pipelines may make welds of relatively less significance, but other joints are potentially susceptible to failure. In particular, failure of mechanical/compression couplings has been the cause of a number of serious incidents on distribution pipelines. PHMSA has made some editorial changes to this section in response to other comments, but has not reorganized it. The first portion of this section relates to the portion of the pipeline involved—body of pipe or type of joint. Some of the joint types are applicable to metal and some to plastic, but the reporting operator only needs to select the single appropriate entry. The latter portion poses questions that are applicable to all pipe types. PHMSA considers this organization appropriate.

Compression couplings: NAPSR recommended that compression couplings be identified as a separate sub-cause. Failure of compression couplings has been the cause of a number of serious gas distribution pipeline incidents.

PHMSA response: PHMSA agrees and has made the recommended change.

Additional information required: NAPSR suggested including “previous damage” as one of the potential causes of failure. AGA suggested deleting “design defect” since they believe that it is unclear.

PHMSA response: PHMSA agrees with NAPSR and has made the recommended change. PHMSA did not make the change AGA suggested. PHMSA considers that design defects are a condition that could influence joint failures. PHMSA will add additional clarification in the instructions.

Plastic joints: AGA and Southwest suggested that “butt, electrofusion” duplicates “socket, electrofusion” and that one of them should be deleted.

PHMSA response: PHMSA disagrees. The electrofusion process may be the same. The presence of a pre-formed socket potentially affects the fit-up process and can affect the integrity of Start Printed Page 41503the joint. PHMSA considers it worthwhile to collect data at a level of detail that would reflect these differences.

Pipe seam: Southwest questioned why the type of pipe seam was no longer of interest for seam failures.

PHMSA response: PHMSA agrees that this information is potentially important and has revised the form to restore the specification of seam type from the present form.

Pressure tests: NAPSR and Southwest recommended that the question of whether a hydrostatic test has been conducted since installation be deleted. They noted that hydrostatic tests are generally not performed for distribution pipelines. Southwest also noted that it may be difficult to determine the actual test pressure.

PHMSA response: PHMSA acknowledges that pressure tests are conducted rarely, if ever, for many distribution pipelines subsequent to initial construction, and that air or natural gas is often used as the test medium rather than water. PHMSA has revised this question to refer to pressure tests vs. hydrostatic tests. The fact that pressure tests may be rare for some distribution pipelines is not particularly relevant. Operators who have not conducted pressure tests since installation would simply check “no” for this question. PHMSA considers that whether a pipeline that has failed (i.e., suffered an incident) had been tested is an important piece of information. PHMSA recognizes that a precise determination of test pressure may be difficult, but notes that an estimate of the test pressure should be easier to obtain and will be sufficient. PHMSA will clarify the instructions to discuss the expected degree of precision.

Part F, F6—Equipment Failure

Non-threaded failures: NAPSR suggested deletion of the clarification “NOT pump seals” since pumps are not used in distribution pipeline systems.

PHMSA response: PHMSA has made the suggested change.

Malfunction of control/relief equipment: IUB noted that the reason for a failure is an important piece of information not collected.

PHMSA response: A description of the failure/incident can always be included in Part G. PHMSA saw no reason why this particular incident cause should be separately identified as requiring additional explanation.

Non-threaded connection failure: IUB noted that O-rings and gaskets are seals and questioned why operators were asked to specify either of these or “seal or packing.”

PHMSA response: PHMSA agrees that O-rings and gaskets are, technically, types of seals. They are, however, in common use and generally referred to as O-rings and gaskets rather than as seals. PHMSA has modified this question for clarity to make the choices O-rings, gaskets, and “other” seals or packing.

Part F, F-7, Incorrect Operation

General: APGA noted that the instructions for this section do not address all of the sub-causes. They also questioned the value of sub-categorizing these incidents.

PHMSA response: PHMSA will revise the instructions. PHMSA cannot know at this time the value of collecting information at the sub-category level, because the data has not previously been collected. PHMSA considers it worthwhile to collect this data to determine if there are sub-categories of incorrect operation that may require additional regulatory attention. Operators completing reports will only be required to check the box for the appropriate type of mal-operation, so PHMSA concludes that the additional burden required to collect this information will be minimal.

Valve left or placed in wrong position: NAPSR suggested deleting reference to caverns since cavern storage is not a part of distribution pipelines. Nicor suggested that the term “storage” be defined

PHMSA response: PHMSA has deleted all reference to storage. The question had asked whether incorrect valve operation resulted in overpressurization of storage. PHMSA has revised this question to ask simply whether overpressurization, of any pipeline portion/component, resulted.

Part F, F8—Other Cause

Still under investigation: For incidents still under investigation, the form noted that a supplemental incident report was required. NAPSR suggested modifying the form to require that this report be submitted within one year.

PHMSA response: The regulation requires supplemental reports, as deemed necessary, when additional relevant information is obtained. The regulation does not, however, specify a maximum time frame in which such reports must be submitted. PHMSA cannot use this change in the incident report form to impose such a requirement. PHMSA will modify the instructions to state its preference that supplemental reports addressing additional investigation be submitted within one year of the submission of the initial incident/accident report.

Instructions for Incident Report Form PHMSA F 7100.1—Gas Distribution Systems

In response to many of the comments received, PHMSA has revised the instructions to reflect changes made in the form and for editorial purposes. PHMSA also received the following specific comments on the instructions:

Duplication of the form: Many commenters noted that a large portion of the proposed instructions was duplicative of the information already provided on the incident reporting form and that such information could be deleted. These commenters also suggested that the instructions should only provide additional guidance, where needed, and that eliminating unnecessary or duplicative information would significantly shorten the instructions and make them more useful.

PHMSA response: PHMSA agrees and has deleted unnecessary duplication.

Reporting to State regulators: NAPSR and State regulators suggested that the instructions include a reminder to operators of their obligations to comply with any applicable State reporting requirements.

PHMSA response: PHMSA agrees and has added such a reminder.

Time to report: NAPSR noted that the indication that incidents are to be reported to the National Response Center by telephone within 24 hours was a deviation from past practice. The regulation, 49 CFR 191.5, requires that telephonic reports be made “at the earliest practicable moment.” NAPSR notes a long-standing interpretation that such reports should be made in 2 hours and questions the change to 24 hours.

PHMSA response: PHMSA agrees that this was an unintended change and has revised the instructions to reflect the long-standing 2-hour interpretation.

Cost guidance: NAPSR and MOPSC suggested that additional guidance be provided for estimating costs associated with an accident. Specifically, they suggested including guidance published in advisory bulletin ADB-94-01.

PHMSA response: PHMSA has included the guidance from the advisory bulletin.

Incidents significant in operator's judgment: An incident is defined as an event that meets certain threshold criteria or is otherwise “significant, in the judgment of the operator.” 49 CFR 191.3. Southwest requested that the form include guidance on PHMSA's policy toward reporting the latter category of incidents, i.e., those based solely on the operator's judgment.

PHMSA response: PHMSA does not believe that the provision of any Start Printed Page 41504additional guidance on this issue is appropriate or required at this time. However, PHMSA reminds operators that Form F 7100.1 must be completed and submitted regardless of whether an incident is based on the specific threshold criteria or an operator's judgment.

Classification of fatalities: Southwest suggested that the guidance on reporting an injury that ultimately results in fatality raises Health Insurance Portability and Accountability Act (HIPAA) concerns.

PHMSA response: PHMSA disagrees. The identified guidance simply states that injuries that result in a fatality within 30 days of an incident should be reported as fatalities and that injuries that result in a fatality beyond that time should be reported as injuries. This is consistent with DOT's general guidelines and does not involve information protected by HIPAA.

Comments on Burden Estimate, Form 7100.1, Incident Report—Gas Distribution System

Investigation Burden estimate: NAPSR and State regulators commented that the burden estimate did not account for the burden on State regulatory agencies to investigate incidents.

PHMSA response: The burden associated with investigations is not related to the information that is collected via this form and has been appropriately excluded.

Burden estimate: SoCal/SDG&E, Nicor, and MidAmerican commented that the burden for completing the form (estimated at 7 hours) was significantly underestimated. MidAmerican contended that the total time required to complete the form could be 20 to 40 hours or longer for complicated events. SoCal/SDG&E suggested that the burden could be reduced by redefining the thresholds for reporting incidents.

PHMSA response: The operators provided little information in support of their contention. Nicor and SoCal/SDG&E simply stated that the burden was greater than estimated by PHMSA. MidAmerican provided estimates of hours that would be required to complete some sections of the form, but without substantiation. PHMSA agrees that complicated events may take longer, but notes that the shorter time that will be required for more “simple” events will balance this out. PHMSA believes that MidAmerican's estimates are excessive. Even if completion of the form would require more than the seven hours estimated, the total burden of this information collection is still minimal. Operators need only complete the form if they have an incident. There are approximately 150 incidents annually on gas distribution systems, and it is rare for an individual operator to experience more than one. PHMSA considers that the value of this information for future analysis of incident trends and the factors that influence the occurrence of incidents justifies the information collection burden. The threshold for reporting incidents is defined in the regulations and no change to those regulations has been proposed. Changing the threshold is beyond the scope of this information collection request.

B. Incident Report Form PHMSA F 7100.2, Gas Transmission and Gathering Systems

General Comments (Impacted Information Collection: OMB 2137-0522)

Definition of incident: INGAA suggested that any information collection should be limited to only those events that meet the reporting thresholds for unintentional releases of gas, a limitation not included in the definition of incident in 49 CFR 191.3, but one that is included in the definition of incident in ASME/ANSI B31.8S (referenced in 49 CFR 192.945). Panhandle also suggested that a modification of the definition of incident, particularly given the recent change in the price of natural gas, should precede any change to the accompanying reporting form.

PHMSA response: The definition of an incident is established by regulation and can only be changed in a notice-and-comment rulemaking, an action that is beyond the scope of this information collection request.

Report vs. investigation: INGAA and certain pipeline operators argued that PHMSA's proposed changes to the reporting form go beyond what is necessary to report an incident and are tantamount to requiring a root cause investigation. INGAA suggested that this would likely mean that most of the incident reports submitted in 30 days would be incomplete. INGAA further suggested that the additional data items included in the new form actually undermine the original purpose of incident reporting. INGAA suggested that a rulemaking should be initiated if PHMSA wants to make changes of this magnitude.

PHMSA response: PHMSA agrees that the revised form is designed to collect new, and in some cases more detailed, data on incidents. However, PHMSA has determined that this information is needed to identify trends in the occurrence of safety-related problems, to appropriately target its performance of risk-based inspections, and to assess the overall efficacy of its pipeline-safety regime. Furthermore, PHMSA does not agree that a root cause investigation must be conducted to complete the revised form. On the contrary, PHMSA is confident that a prudent operator can complete the form in a reasonable amount of time based on the information available at or near the time of the incident. While the number of incidents that occur annually has declined in recent years, PHMSA remains committed to reducing the occurrence and mitigating the consequences of these adverse events, and more detailed data is required to support these analyses.

Relationship to pending rulemaking: INGAA and AGA argued that the data sought on potential controller involvement exceeds current regulatory requirements. INGAA and AGA also noted that a rulemaking on control room management is pending and suggested that any changes to the incident reporting forms be deferred until that proceeding is completed. Nicor, Paiute/Southwest, and SoCal/SDG&E also supported removing these questions pending completion of the control room management rulemaking.

PHMSA response: Congress has mandated that PHMSA use its broad authority to collect information on pipeline facilities, 49 U.S.C. 60117(b)(1)-(2), to obtain specific data from owners and operators on the role of controller fatigue in incidents and accidents. Pipeline Inspection, Protection and Safety Act (PIPES Act) of 2006, Public Law 109-468, section 20, 120 Stat. 3498 (Dec. 29, 2006). However, rather than addressing that mandate in isolation, PHMSA is coordinating its collection of that information with its pending rulemaking on control room management. Transmission lines are a key part of the nation's pipeline network, and Congress has determined that additional information on the contribution of controller fatigue to the occurrence of incidents and accidents is vital to PHMSA's safety mission. These authorities provide ample support for collecting all of the information sought in the proposed revision to the incident reporting form without further delay.

Time to implement: INGAA estimated that it could take up to 6 months to fully integrate the new incident reporting form and suggested that a stay of enforcement be granted with respect to any reporting problems that arise during this time. SoCal/SDG&E suggested that operators be allowed a period of three months after publication to begin using the new form. Paiute/Southwest Start Printed Page 41505suggested that the substantial changes made in the incident reporting form justify PHMSA's sponsoring of a workshop to allow operators and other affected parties to discuss the underlying issues.

PHSMA response: PHMSA does not agree that the proposed incident reporting form is significantly more complicated than its current counterpart. To the contrary, PHMSA has structured the new form to make it much easier to complete than the current form in most instances. Similarly, PHMSA has determined that most of the information requested should be readily available within the 30-day reporting period, and that any new data can as in the past be submitted in a Supplemental Report. Nevertheless, PHMSA will host a Web Live Meeting or similar forum when the new form is issued to explain its contents and demonstrate its proper use. PHMSA will also consider posting these broadcasts on its Web site for later reference.

Part A, Key Report Information

Question 1 and 2, Operator identification: IUB suggested that a mailing address is still needed for any official correspondence that may be needed in response to an incident. In particular, IUB noted that while PHMSA may have access to an address through its OPID system, others seeking to contact the company may not have access to that information.

PHMSA response: PHMSA agrees and has made the suggested change.

Question 4, location of incident: NAPSR suggested adding “GPS Coordinates” and “Projection” to provide clarity and better define the latitude/longitude data.

PHMSA response: Appropriate guidance will be included in the instructions. The current state of GPS location technology is such that these sorts of descriptors are no longer necessary.

Question 6, time and date of telephonic report: INGAA and Panhandle suggested deleting this element since it could conflict with information recorded by the National Response Center (NRC). They suggested that the NRC could provide this information if needed.

PHMSA response: This information is important to demonstrate that the NRC was notified as required. This information is also important in PHMSA's evaluation of the timeliness of an operator's NRC reporting and subsequent follow-up. It adds minimal burden and will assure that the information is captured in the same database as other information related to the incident. PHMSA has retained this element.

Question 7, commodity released: Several commenters noted that “spilled” is an inappropriate term for gas and should be replaced with “released.” INGAA and Panhandle also suggested that the terms “wet” and “sour” should be defined and that the term “synthetic gas” is not clear. INGAA also commented that releases of propane would be hard to detect and that this commodity is generally not transported via transmission pipelines. Panhandle questioned why propane, which they contend is a hazardous liquid, is on the list. NAPSR suggested collecting the following data for sour gas: H2 S__ grains/100cf or __ ppm and replacing “[Neither]” with “[Other/Specify:__].” They suggested that operators completing reports could specify could specify [Dry], P/L quality gas. NAPSR also noted that a number of the releases in question 31 could involve significant quantities of liquids and asked whether the volume of these liquids should be reported.

PHMSA response: PHMSA has changed “spilled” to “released,” and eliminated the questions pertaining to whether the gas released is “wet” or “sour” due to the limited usefulness of that information in ensuring public safety. Synthetic gas and propane gas have been retained. Though rare, these are transported commodities which could be involved in a reportable release. A question requiring the operator to report the amount of liquid that accompanies a gas release has been added.

Questions 9 and 10, volume released: NAPSR suggested that the acronym MCF be spelled out to avoid confusion. They noted that this typically refers to thousands of cubic feet, but that M is also used in engineering applications to denote millions. INGAA suggested revising the language of these questions to replace gas released unintentionally with gas released during the incident and gas released intentionally with gas released during mitigation and repair. MidAmerican, Paiute/Southwest and SoCal/SDG&E noted that it can be difficult to estimate the amount of gas released and to differentiate between what is intentionally and unintentionally released. They suggested simply reporting the estimated total volume released. Atmos agreed that the form should indicate that the amounts reported are expected to be estimates. Panhandle questioned the need to report any quantity of gas released unless it is associated with a criterion defining a reportable incident.

PHMSA response: “MCF” has been spelled out to eliminate confusion, and the questions have been revised to clarify the unintentional vs. intentional amounts of any gas released. PHMSA recognizes that it may be difficult to estimate released volumes in some situations. PHMSA only expects that a reasonable estimate be made based on the facts of the incident known by the operator, and will explain this in the instructions.

Questions 11 and 12, number of fatalities and injuries: Several commenters questioned the need for some of the information sought in these questions. For example, INGAA and Nicor suggested omitting the numbers of emergency responders and non-operator personnel working on the right-of-way, characterizing that information as without value and ambiguous. Paiute/Southwest also suggested that the category of “emergency responders” be limited to non-operator personnel as operator employees and contractors are addressed in other categories. Paiute/Southwest also noted that pipelines may be located in areas other than a right-of-way. Finally, Panhandle questioned the need for any of the detailed information sought, suggesting instead that all that is needed is a yes/no answer as to whether fatalities or injuries occurred and, if so, a number.

PHMSA response: Because utility rights-of-way are used for purposes other than gas pipelines, employees or persons associated with other utilities (e.g., electric, other pipelines) may be performing work on the right-of-way at or near the time of an incident. PHMSA considers it important to collect data on this category of the “public” to determine if common location of utilities is a factor that contributes to incident frequency. Similar situations exist for other pipeline types with other pipelines/utilities installed in common rights-of-way/easements, and PHMSA also collects this data for those pipelines. For these reasons, PHMSA has retained this category. PHMSA agrees with Paiute/Southwest that the emergency responder category was intended to apply to responders not employed by the pipeline operator and has modified the form accordingly.

Question 13, was pipeline shut down: NAPSR suggested that information on the exact date and duration of pipeline shutdown be collected, noting that this may occur on the date of or subsequent to the incident depending on the circumstances presented. INGAA suggested that this question be either deleted or limited to situations where a shutdown or reduction in the capacity of a pipeline occurred for an extended Start Printed Page 41506period. They contended that wide variations in the nature and duration of shutdowns would make this data of limited use and noted that details necessary to understand these variations were not being collected. Paiute/Southwest suggested that it allow for reporting of shutdowns affecting just the portion of the system in which the incident occurred. MidAmerican suggested that the duration of a shutdown is not relevant, as pipelines can remain shutdown for a variety of reasons that may not be related to the incident. Panhandle questioned the relevance of this information and suggested that the question be deleted.

PHMSA response: PHMSA recognizes that there can be wide variations in the nature, cause, and extent of shutdowns. However, PHMSA has concluded that the information is needed to enable the agency to better determine the full extent of the impact on the overall reliability of the nation's pipeline infrastructure caused by the incident. For example, shutdowns and failures can adversely affect the broader public through the loss of heat during cold periods, and the impact on at-risk communities, including homes, hospitals, nursing homes, can be particularly severe. Nonetheless, in response to the comments received on the notice, PHMSA has modified this question to collect information specific to shutdowns on the time of the shutdown, the time the incident was identified, the time that operator resources arrived on site, and the time the facility was restarted, from which meaningful durations and intervals can then be calculated.

Questions 14 and 15, did commodity ignite/explode: INGAA noted that the term explosion is highly subjective and suggested these two questions be consolidated into a single question on whether the released commodity ignited. Panhandle agreed, noting that while an ignition might sound like an explosion a true explosion cannot occur unless gas is contained.

PHMSA response: PHMSA has used the terms “fire” and “explosion” in the past without controversy and does not believe that the few isolated situations where the difference between a fire and an explosion might be relevant warrants the changes INGAA and Panhandle suggested.

Question 16, number evacuated: MidAmerican recommended that the heading be changed to “Estimated Number of General Public Evacuated if Known.” They suggested that the number of evacuees is likely to be unknown, because emergency services call for evacuation in an informal manner and people self-evacuate. Panhandle also stated that this number would be difficult to estimate for the same reasons.

PHMSA response: PHMSA recognizes that this data will be an estimate and may be subject to some uncertainty, but does not consider that changes to the form are needed. PHMSA expects operators to exercise reasonable diligence in estimating the number of people evacuated. The instructions will so state.

Question 17, elapsed time: NAPSR suggested that this question be revised to request a time sequence, similar to the changes they suggested for Form F 7100.1, Gas Distribution Systems. Several pipeline operators noted an inconsistency between the form and the instructions for this question. Paiute/Southwest questioned the use to which this data will be put, contending that the implied development of a national response time for an incident would be inappropriate due to differences in the circumstances of different pipeline operators in widely varying geographic locations. Panhandle questioned the value of this question, commenting that there are incidents in which operating personnel would not go to the site.

PHMSA response: PHMSA has modified this question to provide for a time sequence, similar to the change made to the gas distribution system incident report form. PHMSA has addressed the inconsistency with the instructions. PHMSA considers that it is very unlikely that a reportable incident (i.e., an event involving a fatality, serious injury, or $50,000 in property damage) will occur without some representative of the operator being dispatched to the site. The time sequence asks when “operator resources” arrived, which would account for situations in which the personnel dispatched are contractors rather than operator personnel. PHMSA has no intention to develop a national response time limit.

Part B, Additional Location Information

Questions 20 and 21, address: NAPSR suggested separate lines be provided for City and County/Parish. NAPSR also suggested adding other options to identify locations between station numbers and to provide a segment ID and the name of the pipeline. IUB commented that the form should retain the option to provide location by section, township, and range, as this is still the best way to identify a location in rural areas. MidAmerican suggested deleting questions 21-23, based on the assumption that operators would provide geographic coordinates. INGAA suggested that question 20 should allow for, but not require, a “zip plus 4” zip code. Panhandle noted it is sometimes difficult to obtain zip codes for sites in rural areas.

PHMSA response: The form has been modified to separate City from County/Parish, to add space for a Pipeline Name and Segment ID and to allow for, but not require, a “zip plus 4” zip code. PHMSA considers the available options to identify location to be sufficient.

Question 22, operator designated location: INGAA noted that transmission pipelines associated with distribution systems are unlikely to be designated by milepost/valve station or survey station number. INGAA and Paiute/Southwest contended that the latitude/longitude information provided in question 4 should be sufficient and suggested deleting question 22.

PHMSA response: PHMSA must be able to identify the precise location of an incident for either contemporary or future purposes. The milepost/valve station/survey station information provides a designator that allows later determination of the precise location of the incident on operator drawings and records, while the latitude/longitude information allows for the incident's precise location on-site or geographically, both of which are essential for further investigation and analysis.

Question 23, Federal lands: NAPSR suggested a breakdown by type of Federal land, e.g., Military, Tribal Reservation, BLM, Forest Service, Park Service.

PHMSA response: The statutory basis for issuing pipeline rights-of-way on Federal lands is 30 U.S.C. 185, and the purpose of this question is to identify incidents that occur on lands subject to that code section. Section 185 does not require a breakdown by type, as suggested by NAPSR. PHMSA does not see the utility in requiring this additional level of detail, nor does it envision any risk evaluations where this information might prove valuable.

Question 24, location of incident: NAPSR suggested requiring a name/identification for lakes, rivers, streams, or creek crossings, noting that this information can be useful and is usually readily obtainable. Nicor and Columbia suggested that “high consequence area” be used instead of “covered segment” as the term is more readily recognized. They further commented that the method by which a high consequence area (HCA) was determined and whether it is based on an identified site are not relevant and both elements should be deleted. INGAA and Panhandle noted that the method of Start Printed Page 41507determining an HCA may vary over time and that this data will thus be of limited use for trending. INGAA and Panhandle also suggested that class location be part of a separate question and questioned the value of additional data elements added to this question. They recommended that this item be limited to determining whether the incident happened in an HCA and its class location.

PHMSA response: The name of the water body being crossed has been added. And the term “high consequence area” has replaced “covered segment” to reflect the term already defined in regulation and to reduce the potential for confusion. Identification of the method by which an HCA is determined is essential to PHMSA's ability to assess and validate the basic approaches operators use to determine this critical, safety-related calculation. Identification of Class Location—another primary safety indicator—has been segregated out and rewritten as its own question as suggested.

Question 25, approximate water depth: INGAA and Panhandle noted that this question will be confusing for incidents that occur offshore in piping on platforms, i.e., not below the surface. INGAA suggested first asking if the incident occurred on a platform and only asking water depth for those offshore incidents that did not.

PHMSA response: The instructions will make clear that this is intended to be the water depth at the location of the incident, even if the incident occurs on a platform, and not the depth of the incident below the water.

Question 26, origin in State waters: For offshore incidents in State waters, NAPSR suggested requiring specification of the State, the Area, and the Block/Track as this is useful identifying information. Paiute/Southwest requested clarification as to the term “origin of the accident” and whether “in State waters” refers only to commercially navigable waterways.

PHMSA response: For offshore incidents in State waters, the form has been modified to obtain Area and Block/Track information to more accurately locate the incident. Commercially navigable waterways may or may not exist offshore. For an incident to be considered both “offshore” and “in State waters,” the incident would by definition not be in inland waters. This “offshore” determination would be made without regard for whether the waters were commercially navigable or not.

Question 27, area of failure: Nicor and Atmos objected to the use of the undefined term “failure” in this question and commented that an incident may result from circumstances outside the control of a pipeline operator, e.g., impact by a non-operator vehicle and not from a “failure” of the pipeline. Nicor also noted that options for normally buried pipe and aboveground appurtenances need to be provided. IUB also noted that the options available on the form were not adequate to address many situations. For example, IUB noted that most underground pipelines are simply buried under soil, but that this is not one of the options for selection. Instead, it would need to be reported as “other” and described. IUB considered it inappropriate that reporting of the most common situation should be relegated to “other.” For transmission pipelines, IUB noted that the likelihood of pipelines being buried under a building is so remote that this option should be deleted. INGAA and Panhandle recommended adding depth of cover for underground facilities, information that is currently collected and has proven valuable. Paiute/Southwest requested clarification of the term “open ditch.”

PHMSA response: PHMSA has replaced the word “failure” with “incident” to the extent practicable. Nonetheless, there are still some situations where the use of “failure” in its common definition is necessary and would not be confusing. The selections for Underground and Aboveground locations have been refined and expanded upon, each retaining an “Other” category to capture situations not expressly identified in the selections offered. Under soil has been included. For Underground facilities, depth-of-cover has been added as suggested.

Part C, Additional Facility Information

Question 28, pipeline function: MidAmerican commented that the term “Transmission Line of Distribution System” needs to be defined.

PHMSA response: This is intended to refer to a pipeline classified as transmission (usually due to operating stress levels) but operated as part of a distribution pipeline system. This will be defined in the accompanying instructions.

Question 30, part of system involved: INGAA and Panhandle commented that the data required for this question would be of little or no value and suggested that the choices be limited to below ground storage including piping, above ground storage vessels and piping, pipelines, compressors, and metering/regulation, and that all the offshore data elements should be deleted. Nicor also questioned the value of the offshore elements for incident trending and analysis.

PHMSA response: The categories have been adjusted to reflect these comments, with the exception of the elimination of the offshore elements. Offshore pipelines and facilities represent a very distinct and different set of conditions and risk factors—and available preventive and mitigative measures—than onshore pipelines and facilities, so we have retained offshore elements to capture them separately. We have deleted the collection of detailed offshore data elements relating to valving and isolation.

Question 31, item involved: INGAA and Panhandle questioned the value of many of these data elements for incident analysis, noting that the list of potential pipe coatings and equipment types is not complete and that a complete list could be very long. INGAA and Panhandle also suggested many of the seldom-involved elements be deleted. MidAmerican also commented that providing the amount of data required would be burdensome and questioned its value. For example, MidAmerican noted that pipe seam type would be of little interest for an incident resulting from excavation damage and that coating type is relevant only if the incident is caused by corrosion. Panhandle commented that this section is unclear if an incident involves other than pipe or a valve, and noted that compressor is addressed here and in Part F6. Panhandle also suggested that operators be required to only provide the information that is relevant, suggesting, for example, that wall thickness and SMYS of the pipe are not important if the incident involves a valve. NAPSR recommended adding joint as an element and requiring that the joint type be specified. Commenters noted that some of the information may not be known for older pipelines and that the form should accommodate this by allowing a response of “unknown.” Atmos questioned whether extruded polyethylene is a coating type. SoCal/SDG&E suggested that pipe specification should be better defined. Nicor suggested changing “failure” to “incident.”

PHMSA response: Choices have been expanded and modified based on comments received, with an “Other” category as an option for those situations not identified by the other choices. PHMSA considers the item involved in an incident to be a basic piece of data that should be captured for all incidents. Additional data is only being collected as it pertains to the individual item selected as being involved in the incident. In particular, Start Printed Page 41508with pipe being such a critical component that represents a vast majority of any pipeline asset, PHMSA believes that basic information pertaining to the pipe will be valuable for a number of analyses and also to better understand the basic characteristics of any pipeline system. We have changed “failure” to “incident” wherever practicable throughout the form.

Question 33, material involved: IUB suggested that the type of plastic be requested when an incident involves plastic pipe as well as additional information to specify the particular plastic. INGAA and Panhandle suggested that the response options be limited to steel, plastic, and other. They contended that additional information is not needed for plastic pipe, since plastic pipe is seldom used in transmission pipelines.

PHMSA response: The choices have been limited to steel, plastic, and other. PHMSA agrees that plastic pipe is not prevalent enough in transmission or gathering service to warrant capturing the type of plastic used.

Question 34, type of failure: INGAA and Panhandle noted that the proposed form no longer asks for information concerning puncture size and also omits other questions from the current form. They believe that this information has proven useful and should be retained. INGAA and Panhandle noted that overpressure is a potential cause, but not a type of failure. Nicor and Columbia suggested that there are other types of mechanical damage of potential interest besides punctures. IUB suggested value in requesting the type of joint failure for cases of failure of plastic pipe joints.

PHMSA response: Puncture and Rupture size information has been restored. We have removed overpressure as a “Type” of incident, and Connection Failure and have included it as a sub-category to accommodate threaded connections or other types of joints.

Part D, Additional Consequence Information

Question 35, potential impact radius (PIR): INGAA, Panhandle, and Columbia suggested deleting this question, noting that it is only relevant for an HCA and then only if method 2 was used to identify HCAs. Paiute/Southwest noted that PIRs are not calculated if method 1 is used. Some commenters also contended that the need for this information as part of an incident report is not obvious. INGAA and Panhandle also suggested that the related requirement to describe the incident footprint in the narrative be deleted, in part because the footprint will reflect subsequent material fires and will not be directly proportional to the size of a pipeline leak or rupture. Several commenters noted that PIR should be spelled out as potential impact radius (as opposed to a circle) and that the dimensions in which the size is to be reported (feet) should be included.

PHMSA response: We have modified the form so that the PIR is only required to be reported when it was calculated by the operator. The descriptive information pertaining to an incident footprint has been omitted; however, if and when an incident has occurred in an HCA, it is very important for PHMSA—as well as the operator—to understand if there were any impacts beyond the calculated PIR, and to what extent these impacts existed. If impacts of incidents are often found to extend beyond the calculated PIR, it could indicate a need for PHMSA to revise the PIR definition. As a result, several specific questions asking about these impacts now replace the more general descriptive information about the incident's footprint.

Question 36, cost data: INGAA noted that the difficulties in estimating the amount of gas released intentionally and unintentionally (see question 9 and 10 above) also apply here. They further suggested that the cost of the commodity be deleted, since it appears that the reporting basis will now be volume released. They suggested that cost of repair should be limited to repair of the pipeline facility and should not include costs to repair property of others. INGAA also noted that the cost of emergency response by others may be impossible to know. Columbia also noted that the information desired for cost of emergency response requires clarification. NAPSR suggested that emergency response costs be limited to those borne by the operator. Nicor and Atmos suggested that this element be deleted, along with cost of repair, since those costs are not required to be considered by 49 CFR 191.3 in determining whether an incident has occurred. Several commenters also requested that the form explicitly recognize that the reported costs are expected to be estimates. Paiute/Southwest asked for guidance concerning what estimated costs are sufficient to submit a “final” report, noting that some repair and restoration costs (e.g., repaving) can be incurred over a significant period of time. NAPSR suggested consideration be given to adding “customers out of service” as done on the distribution pipeline form.

PHMSA response: The revision to this form does not change the criteria that define an incident under 49 CFR 191.3. Nevertheless, costs are incurred for repairs and for emergency response when most incidents occur, and consideration of these costs helps identify the relative significance of an incident. Thus, PHMSA considers it appropriate to collect this data. PHMSA agrees that it would be an unreasonable burden to require operators to estimate the costs incurred by outside emergency response agencies and has limited this factor to costs incurred by the operator to cover their emergency response activities. PHMSA has modified the form to note explicitly that the reported costs are expected to be estimates, including the cost of gas lost both unintentionally and intentionally as these are key components in evaluating the overall impacts of incidents. PHMSA considers that attempting to determine the “customers out of service” for gas transmission and gathering incidents would in most cases be too far removed from the incident involved and too difficult to obtain with any degree of certainty.

With respect to the question asked by Paiute/Southwest, PHMSA does not consider it practical to provide definitive guidance for when cost estimates are to be considered final. That determination will vary depending on the facts and circumstances of each particular incident and inherently requires an exercise of judgment by the operator. PHMSA expects that all significant costs associated with an incident will be estimated as part of the initial or a supplemental incident report, regardless of whether those costs are incurred soon after an incident or at some later time. An operator's judgment in this regard will be reviewed as part of the regulator's investigation of an incident, and additional supplemental incident reports may be requested if PHMSA (or its State partner agency) concludes that significant costs have not been included in reported estimates. It is important that PHMSA account for and understand the true and total costs of incidents which occur, not just to allow for a reasonable accounting to the public and other stakeholders, but also to improve the accuracy of any future cost-benefit analyses that PHMSA performs.

Part E, Additional Operating Information

Question 37, special regulatory circumstances: INGAA and Panhandle suggested that this question be deleted as an operator must typically report incidents in other reports required by the regulatory documents listed. Columbia and Nicor suggested that there Start Printed Page 41509needed to be an option for “none” or “NA.”

PHMSA response: PHMSA has deleted this question.

Question 39, MAOP: The question asks under which regulatory requirement the MAOP was determined. IUB suggested that it should also ask what the MAOP is. INGAA noted that this should be the MAOP at the point of the incident. MidAmerican recommended that the proposed paragraph asking how the MAOP was determined be deleted as irrelevant, since an MAOP determined under any of the cited regulations is acceptable and the method by which an MAOP has been determined will have no relevance to the occurrence of an incident. Panhandle noted that a change to this question may be needed to accommodate an MAOP of 80 percent SMYS.

PHMSA response: PHMSA has retained this set of questions from the existing reporting form. PHMSA agrees with Panhandle that SMYS information is increasingly important considering the agency's recent rulemakings allowing operators to increase SMYS up to 80 percent. We retained this set of questions from the existing report form, but updated the selections for SMYS determination to reflect recent rulemakings.

Question 40, overpressurization: INGAA and Panhandle suggested that this question requires clarification as to whether pressures exceeding MAOP or MAOP plus some allowable margin (e.g., 10 percent) were experienced. IUB suggested that a positive answer should require that the operator also report normal operating pressure, MAOP, and pressure experienced to provide the context for an overpressure event.

PHMSA response: This question has been modified to clearly indicate which pressure range was exceeded when an overpressure occurred. PHMSA has not modified the form to collect normal operating pressure. MAOP is already collected, and operation at any pressure below MAOP is acceptable. PHMSA thus concluded that normal operating pressure (which may be below MAOP) is not needed.

Question 41, SCADA: INGAA recommended that this question be deleted as irrelevant. They note that the existence of a SCADA system does not indicate any relevant information about whether the system recorded/transmitted information concerning the incident site. Panhandle also noted that a SCADA system may be in place for nearby compressors, for example, but provide no information relevant to the incident. They asked how an operator would complete this section in such a case. Columbia also supported INGAA's comment, noting that a SCADA system may monitor areas not associated with the incident. NAPSR recommended an additional question asking if the SCADA system was operating, since it is possible that a SCADA system may exist but not be in use.

PHMSA response: PHMSA considers it appropriate to collect this information. PHMSA has explicitly included a question asking whether SCADA-based information assisted in detection of the incident. This will allow operators to identify situations in which the presence of the SCADA system was not relevant to the incident.

Question 42, how detected: INGAA and Panhandle recommended that this question be deleted. They questioned its relevance, noted that it uses terms not previously defined, and pointed out that SCADA systems do not detect incidents. Columbia and IUB also noted that the terms local controller and remote controller have not been defined. MidAmerican also supported deletion, commenting that how an incident was detected is immaterial.

PHMSA response: PHMSA does not agree that this information is immaterial. PHMSA has revised this question to ask how the incident was identified for the operator, which will accommodate those situations in which the incident was reported by others rather than being detected by the operator. PHMSA will describe what is meant by remote controller and local operating personnel in the instructions.

Question 43, leak duration: INGAA, Panhandle, and Nicor recommended revising this to “release” vs. “leak,” since the latter term presumes a leak existed and may be confusing. Paiute/Southwest questioned how the duration of a leak would be determined. Columbia agreed that “release” would be a better term, but also suggested that “time to make safe” would be a better question. IUB questioned how a “Static Shut-in Test or Other Pressure or Leak Test” would detect a leak and noted that Air and Ground Patrols are unlikely to identify leaks.

PHMSA response: We have deleted this question.

Questions 44-58, controller involvement: INGAA recommended deleting most of these questions as described above under General Comments. Columbia, Atmos, and IUB suggested that there should be no need to provide this information if controllers were not involved with the event. (Columbia also noted its belief that controller involvement is not a major factor in gas transmission pipeline incidents). Panhandle suggested this information need not be reported in any case, and could be requested by PHMSA if needed. Some pipeline operators and IUB noted that question 44 provides no means of reporting that controllers were not involved, only that an operator had not determined that they were involved by the date of the report. NAPSR noted that multiple responses may be needed if more than one controller is involved and that the form does not accommodate this need. NAPSR also suggested clarifying editorial changes. IUB noted that the first question should be whether the pipeline has controllers, since many do not. Panhandle noted that there is no requirement in Part 192 for a SCADA system and suggested that questions concerning SCADA use are trying to apply a requirement not presently in the regulations.

PHMSA response: Consistent with a recommendation made by the National Transportation Safety Board (NTSB), Congress ordered PHMSA to obtain specific data from owners and operators on the role of controller fatigue in incidents reporting forms. Pipeline Inspection, Protection and Safety Act (PIPES Act) of 2006, Public Law 109-468, section 20, 120 Stat. 3498 (Dec. 29, 2006). Nonetheless, PHMSA has reduced the amount of information required by these questions to allow for reporting that the facility was not monitored by controllers or that the operator determined that a review of controller actions was not needed. The revised form also allows for reporting review results that determined there were no control room/controller issues. PHMSA considers that this is the minimum information for it to satisfy the statutory requirement. PHMSA agrees that SCADA systems are not required, but notes that many pipelines incorporate such systems. Questions concerning SCADA do not imply a requirement to add SCADA systems and PHMSA currently has no intention of establishing such a requirement.

Part F, Cause Information

General: INGAA recommended reorganizing this section into ten cause categories to be consistent with ASME/ANSI B31.8S and the reporting required for integrity management.

PHMSA response: PHMSA has chosen to retain its traditional high-level Cause categories to accommodate, to the extent possible, historical trending to include data from incidents already reported. PHMSA has made minor editorial changes to the Causes described on the form to address an NTSB recommendation that PHMSA align their Cause categories between the two Start Printed Page 41510transmission pipeline types—Gas Transmission/Gathering and Hazardous Liquid. In addition to aligning these Cause and sub-cause categories, PHMSA has added several new sub-categories to reduce the number of “Other” incidents currently being reported by the regulated community across all pipeline types. Additionally, PHMSA has reorganized one Cause category significantly to better segregate sub-categories of Causes associated with construction-, fabrication-, installation-, and original manufacturing-related incidents, while adding a new sub-category for Environmental Cracking-related causes such as Stress Corrosion Cracking, Sulfide Stress Cracking, and Hydrogen Stress Cracking.

PHMSA appreciates the importance of the gas industry's ability to cross reference the threat categories outlined in B31.8S with incident Causes captured by PHMSA, and PHMSA has crafted their Cause categories and sub-categories such that PHMSA's incidents can be cleanly mapped to the specific threat categories listed in B31.8S. In addition, by accommodating this cross-mapping of threats and Incident Causes, PHMSA's pending changes to Gas Integrity Management reporting will likewise support future analyses of the B31.8S threat categories against PHMSA incident Causes and Integrity Management reports. With the addition of the new sub-cause categories on PHMSA's form, INGAA and ASME may want to consider revisions to B31.8S to fully account for all of the incident causes that will now be captured in PHMSA's data.

Part F, F1—Corrosion

General: INGAA and Columbia suggested that most of the detailed questions were confusing and would be better addressed through a narrative, if needed at all. They did not consider that this information is valuable for analysis or trending.

PHMSA response: The information being requested is basic information pertaining to incidents caused by corrosion, all of which should be clearly understood and readily obtainable. As corrosion continues to be a leading cause of incidents, the collection of this basic information is essential to PHMSA's efforts at further prevention. Information collected by narrative is much more difficult to use for subsequent analyses.

External corrosion: INGAA and Panhandle suggested that the phrase “or in contact with the ground” was confusing and irrelevant. They suggested the question be changed to, “Was the failed item buried?” Columbia and Panhandle noted that cathodic protection (CP) surveys other than close interval surveys (CIS) are not defined and recommended that reference to them be deleted. Panhandle noted that the year in which CP was initiated may be unknown, particularly for older pipelines. Panhandle also noted that “selective seam” is not a type of corrosion.

PHMSA response: We have eliminated the phrase “or in contact with the ground”. We have clarified the questions pertaining to the types of cathodic protection surveys being conducted. Selective seam corrosion can be considered a “type” of corrosion in the sense that it manifests itself in a fairly distinct fashion, similar to other choices under this question.

Internal corrosion: INGAA and Panhandle noted that the questions relate to operator practices rather than the cause of the incident. They suggested these questions be replaced with the results of a visual inspection, the type of corrosion, and whether the commodity was “corrosive gas.” Paiute/Southwest suggested that some questions could be relocated to a “general” section, eliminating some duplication within the form. Paiute/Southwest also suggested that information on the assessment history be collected. NAPSR suggested adding questions to determine whether corrosion coupons were used and the location of the corrosion failure. MidAmerican stated that it was unclear what was meant by “cleaning/dewatering pigs (or other operations) routinely utilized.”

PHMSA response: Questions relating to visual inspection, type of corrosion, and other contributory factors (like location of corrosion) have been added. A question was also added pertaining to whether corrosion coupons were used. Questions pertaining to operator practices have been retained because PHMSA believes it is important to have a general understanding of the basic preventive measures which were in place prior to the incident occurring.

Part F, F2—Natural Force Damage

High winds: INGAA and Panhandle suggested limiting this question to damage directly caused by high winds rather than including secondary damage such as barges that may have been moved by high winds to impact the pipeline. They contended this latter type of incident should be considered mechanical damage. INGAA and Panhandle also suggested eliminating the question as to whether the high winds were associated with a severe weather event (e.g., hurricane, tornado) as it is too subjective. NAPSR suggested creating a separate sub-category for natural or forest fires and eliminating the sub-question regarding these under the temperature sub-cause.

PHMSA response: PHMSA has modified the question to capture only incidents directly associated with High Winds, placing secondary damage such as may be caused by drifting barges under “Other Outside Force Damage” as suggested. Questions associated with Forest Fires are now segregated so that those associated with Lightning are associated with Natural Force Damage and those which are man-made are associated with “Other Outside Force Damage”. PHMSA has retained the question concerning severe weather events. This question simply asks if the high winds were associated with such an event. If so, operators are asked to identify the type of event (hurricane, tropical storm, tornado, or other). Damage occurring during Hurricane Katrina was extensive. It has been necessary to exclude from analyses reported property damage from incidents that occurred in 2005 so that the outlier magnitude of these damages did not skew the analytical results. In doing so, however, some non-Katrina damages have also been excluded, because PHMSA had no means of identifying which damages were from Katrina-related causes. The Katrina experience demonstrates that it can be necessary to treat severe event-related damages separately, and PHMSA considers it appropriate to collect this data.

Temperature: Paiute commented favorably on treatment of forest fires under “temperature” but asked if it would apply to fires caused by arson.

PHMSA response: Man-made fires, even if forest fires, would be reported under F4, Other Outside Force Damage—Nearby Industrial, Man-made, or other Fire/Explosion as Primary Cause of Incident. Arson which actually takes place on the site of a pipeline facility would also fall under F4, but would be considered “Intentional Damage”. Naturally-occurring forest fires caused (most probably) by lightning would be captured under F2, Natural Force Damage.

Part F, F3—Excavation Damage

Excavation damage: Several commenters suggested changes to the additional information sought for incidents caused by excavation damage. INGAA suggested that most of the questions be deleted, because they are more appropriate for research than for incident reporting. Among the suggested changes were:Start Printed Page 41511

  • Deleting unknown/other as a choice for location, since operators should know the location.
  • Deleting the damage location entirely.
  • Increasing the number of potential locations to include rights of way on public lands.
  • Deleting the question as to whether the pipeline operator belonged to a one-call system.
  • Deleting information as to whether one-call was notified.
  • Requiring detailed information concerning the one-call notification.
  • Requiring additional information about the interaction between the pipeline operator and those making one-call requests.
  • Clarifying the information required for utilities in common trenches.
  • Clarifying that the name of excavator is a company name vs. an individual or deleting the requirement to report the name.
  • Deleting the requirement to provide the name of the excavator.
  • Rearranging the form.
  • Deleting the question as to whether permanent pipeline markings were visible.
  • Eliminating the questions concerning whether the excavator incurred downtime and whether the excavation had been ongoing for more than one month.
  • Deferring to the Common Ground Alliance's Damage Information Reporting Tool (DIRT).
  • Deleting information about circumstances over which the operator had no control.
  • Deleting the question about whether notification of excavation had been received, because excavators are required to notify.
  • Deleting the type of excavator and work performed.
  • Deleting the type of locator.
  • Deleting the owner of an easement.
  • Deleting whether a pipeline was located in a common trench with other facilities.
  • Requiring only mandatory DIRT fields or requiring reporting via DIRT rather than duplicating their reporting requirements.
  • Allowing space to enter a description where the answer is “other”.
  • Eliminating perceived duplication.
  • Adding additional questions concerning vehicular damage events.

PHMSA response: The Common Ground Alliance (CGA) is the recognized authority for preventing excavation damage of underground utilities. The CGA has determined the information necessary to evaluate excavation damage trends via its DIRT system. PHMSA has adopted in this form the fields defined within the DIRT system as mandatory. Collecting information on excavation damage consistent with DIRT will allow for thorough analyses to identify trends related to excavation damage. It will also allow comparative analyses to consider information reported to DIRT by other underground utility operators, thereby expanding the database and potentially affording additional insights.

Part F, F4—Other Outside Force Damage

Fishing: INGAA and Panhandle recommended deleting the check box for fishing or other marine activity not related to excavation, contending that it is adequately addressed as damage by a vehicle.

PHMSA response: PHMSA wishes to maintain this basic distinction between land-based and maritime causes to evaluate the need, if any, for additional regulations or advisories and to coordinate regulatory or advisory activities with the other Federal agencies with jurisdiction over pipeline facilities located in navigable waters, such as the U.S. Coast Guard.

Previous damage: INGAA and Panhandle suggested that the question concerning failure due to prior damage be revised to refer to prior “mechanical” damage. Paiute/Southwest suggested that this question seems to presume that the portion of the pipeline involved was covered by integrity management requirements (presumably because assessment/examination would be required for such portions).

PHMSA response: We have revised the item to include “mechanical” damage. As far as the presumption of coverage under an IMP, operators are not precluded from taking basic preventive measures such as those shown anywhere on their pipeline systems. PHMSA is interested in any such preventive measures which may have been undertaken preceding an incident.

Additional questions: INGAA commented that the additional data related to hydrostatic tests, direct assessment, and non-destructive evaluation are not justified by the small number of incidents from this cause and should be deleted. Columbia agreed that many questions appear to seek general data, appropriate for an investigation but which is not related to a specific incident.

PHMSA response: PHMSA disagrees and has retained the questions pertaining to the data identified by the commenters, i.e., the use of prior hydrotesting, direct assessment, or non-destructive evaluations, as such information is important to furthering the agency's general understanding of the efficacy of these basic preventive measures.

Electrical arcing: NAPSR suggested adding electrical arcing from adjacent facility.

PHMSA response: We have added this under “Other Outside Force Damage”.

Fire-first events: Nicor suggested that this category be deleted as such events should only be reported if additional damage due to the gas release exceeds reporting criteria. Paiute/Southwest questioned if this category is appropriate for reporting incidents initiated by fires caused by arson.

PHMSA response: Changes to this form do not modify the reporting criteria in 49 CFR 191.15, and PHMSA agrees that no incident report need be filed unless those criteria are met. Experience has demonstrated, however, that pre-existing fires have caused damage to pipeline systems that subsequently resulted in damages exceeding the reporting criteria. Two categories of Fire-related causes have been retained—one for man-made fires under “Other Outside Force Damage” and one for lightning-caused fires under “Natural Forces”. Both of these causes have occurred in the past.

Damage by vehicles: Paiute/Southwest suggested that the question implies a need for vehicle barriers. Paiute/Southwest further noted that there are parameters relevant to a complete understanding of vehicle-impact events that will be unknown to pipeline operators.

PHMSA response: As with fire-first events, analysis of pipeline incident data has shown that incidents caused by vehicle impacts are a small but significant percentage of all incidents. Again, PHMSA is not attempting to regulate the operation of vehicles near pipelines, nor is it implying that a vehicle barrier was needed. Therefore, we have removed the questions pertaining to impact barriers.

Prior examinations: Panhandle concluded that the information requested concerning prior assessments or non-destructive examinations was not needed. They noted that there are very few incidents in this category and that the data will thus be of limited, if any, use. They contended that PHMSA can collect the information as part of an investigation.

PHMSA response: PHMSA disagrees and has retained the questions pertaining to the data identified by the commenters, i.e., the use of prior hydrotesting, direct assessment, or non-destructive evaluations, as such Start Printed Page 41512information is important to furthering the agency's general understanding of the efficacy of these basic preventive measures.

Part F, F5—Material and/or Weld Failure

Assessment history: Paiute/Southwest reiterated its concern (see F4 above) that this section presumes the involved pipeline segment was covered by integrity management requirements.

PHMSA response: There is no such presumption. This section asks whether certain assessments or examinations were performed. Integrity management requirements are one reason why they may have been performed, but some pipeline operators also conduct such evaluations as a prudent preventive measure on their own volition even if not explicitly required by the regulations, and whether the pipeline is in an HCA or not. Understanding whether failures occur despite examinations intended to identify incipient failures can be important to future evaluations of the effectiveness of such measures and whether additional assessment or inspection requirements are needed.

Reporting basis: INGAA and Panhandle suggested deleting the first question, which asks the basis on which the subsequent information was developed. They noted that this information is not needed for trending and that subsequent completion of metallurgical examinations or investigations could lead to a need to file a supplemental report to change the response to this question even though the relevant information does not change.

PHMSA response: Though not needed for trending, it is important information that supports the merits of the reported findings, and it is important for PHMSA to understand the veracity of the reported data, especially in these cases where a highly technical mechanism may be involved.

Environmental cracking: INGAA and Panhandle suggested that questions related to environmental cracking, fatigue and stress should be moved to another section, because they do not relate to material failures.

PHMSA response: These new cause sub-categories align more closely with this primary incident cause than any of the others, and because PHMSA did not wish to create a new primary category, they were placed here, but in such a way that they may be segregated for separate analyses.

Additional questions: INGAA reiterated its objection (see F4 above) to including additional questions concerning hydrostatic testing and assessment methods. Columbia again supported those objections.

PHMSA response: PHMSA disagrees and has retained the questions pertaining to prior hydrotesting testing. This information is important to the agency's general understanding of the efficacy of these basic preventive efforts.

Supplemental report required: For incidents still under investigation, the form noted that a supplemental incident report was required. NAPSR suggested modifying the form to require that this report be submitted within one year.

PHMSA response: The regulation requires supplemental reports, as deemed necessary, when additional relevant information is obtained. The regulation does not, however, specify a maximum time frame in which such reports must be submitted. PHMSA cannot use this change in the incident report form to impose such a requirement. PHMSA will modify the instructions to state its preference that supplemental reports addressing additional investigation be submitted within one year of filing the initial incident report.

Prior examinations: Panhandle again commented that the information requested concerning prior assessments or non-destructive examinations was not needed. They noted that this was the third time this information was requested, and that the question concerning hydrostatic tests discounts the importance of the original hydrostatic test.

PHMSA response: PHMSA has already responded to this thread of comments on the importance of obtaining information on prior tests, such as hydrotesting or direct assessment conducted on the failed pipeline segment prior to incident occurrence.

Part F, F6—Equipment

General: IUB suggested that the form require that a description of the failure be included in the narrative provided in Part G.

PHMSA response: A description of the failure mechanism, secondary and contributory causes, and any other factors deemed important to understanding the incident can always be included in Part G. PHMSA saw no reason why this particular incident cause should be separately identified as requiring additional explanation.

Malfunction of control/relief equipment: INGAA and Panhandle suggested that the form allow for multiple selections and that separate selections be allowed for regulators and control valves. Similarly, Columbia noted that block and check valves serve different functions and should not be grouped together.

PHMSA response: These changes were accepted and incorporated.

Compressors: INGAA and Panhandle commented that the question should be limited to compressors, which are part of the pipeline system, and should not include their drivers, which are not. Columbia suggested that additional data elements could be appropriate for compressors including, for example, emergency shutdown systems, relief valve and/or valve failure, pressure vessel failure, or pipe failure.

PHMSA response: We have eliminated motor-driver as a sub-cause, and adopted the additional sub-causes suggested by Columbia.

Connection failures: INGAA and Panhandle suggested that these be moved to another failure cause.

PHMSA response: The connections envisioned here would fall under “Equipment” as the primary incident cause.

Part F, F7—Incorrect Operation

General: INGAA and Panhandle commented that the elements in this section address what happened but do not cover causes, as is done on the current form. INGAA also noted that this section inappropriately implies that storage is separate from gas transmission and asks questions concerning overpressure that are duplicated elsewhere. INGAA suggested replacing the questions in this section with others largely drawn from the current form. Columbia and Nicor suggested that the term “storage” should be defined as it could be interpreted differently by different users. Panhandle suggested that storage be eliminated completely as it is a part of transmission and need not be called out separately.

PHMSA response: PHMSA believes the new sub-causes listed are more proximate to the incident occurrence than those included in the current form. The choices from the current form, however, have been added back in to address the concern that these important root causes were no longer being captured. In addition, PHMSA has added sub-causes to identify the factors involved in overpressurization of storage, a special case of overpressure that warrants the capture of this additional level of detail.

Part F, F8—Other Cause

Still under investigation: For incidents still under investigation, the form noted that a supplemental incident report was required. NAPSR suggested Start Printed Page 41513modifying the form to require that this report be submitted within one year.

PHMSA response: The regulation requires supplemental reports, as deemed necessary, when additional relevant information is obtained. The regulation does not, however, specify a maximum time frame in which such reports must be submitted. PHMSA cannot use this change in the incident report form to impose such a requirement. PHMSA will modify the instructions to state its preference that supplemental reports addressing additional investigation be submitted within one year of filing the initial incident report.

Instructions for Incident Report Form PHMSA F 7100.2—Gas Transmission and Gathering Systems

PHMSA has revised the instructions to reflect changes made in the form and for editorial purposes based on the comments submitted. PHMSA also received the following specific comments on the instructions:

Duplication of the form: Many commenters noted that a large portion of the proposed instructions was duplicative of the information already provided on the incident reporting form and that such information could be deleted. These commenters also suggested that the instructions should only provide additional guidance, where needed, and that eliminating unnecessary or duplicative information would significantly shorten the instructions and make them more useful.

PHMSA response: PHMSA agrees and has deleted unnecessary duplication.

Reasonable effort: SoCal/SDG&E suggested that the instructions should specify that a reasonable effort should be expended to generate required estimates and that supplemental reports are only needed if reported estimates change significantly or if new information results in a change in reportable status of an incident.

PHMSA response: PHMSA generally agrees and has included appropriate guidance in the instructions.

Cost data: NAPSR suggested that additional guidance be provided for estimating costs associated with an accident, including the guidance published in advisory bulletin ADB-94-01. SoCal/SDG&E asked that the instructions specifically recognize that broad costs estimates are acceptable when specific costs cannot be readily determined.

PHMSA response: PHMSA agrees and has incorporated guidance from the advisory bulletin.

Contributing causes: IUB noted that section F instructs the operator to complete only one cause section, but that some incidents could have multiple contributing causes. IUB suggested that this situation be addressed in the instructions.

PHSMA response: Part F is intended to capture the principal cause of an incident and, as indicated in the instructions, operators can provide additional information in the narrative if they determine that contributing secondary causes were important. For these reasons, PHMSA does not believe any additional guidance is needed on this issue at this time.

Comments on Burden Estimate, Form F 7100.2, Incident Report—Gas Transmission and Gathering System

Burden Hour Estimate: SoCal/SDG&E, Paiute/Southwest, and Panhandle commented that the burden for completing the form (estimated at 7 hours) was significantly underestimated. Paiute/Southwest estimated that the burden may be between 12 and 30 hours. Panhandle estimated 52 hours. SoCal/SDG&E suggested that the burden could be reduced by redefining the thresholds for reporting incidents.

PHMSA response: Even if completion of the form would require more than the seven hours estimated, the total burden of this information collection is still minimal. Operators need only complete the form if they have an incident. There are approximately 75 incidents annually on gas transmission and gathering systems. PHMSA considers that the value of this information for future analysis of incident trends and the factors that influence the occurrence of incidents justifies the information collection burden. The threshold for reporting incidents is defined in the regulations and no change to those regulations has been proposed. Changing the threshold is beyond the scope of this information collection request.

Incidents significant in operator's judgment: Section 191.3 defines an incident as an event that meets specified threshold criteria or “is significant, in the judgment of the operator” even though it did not meet those criteria. Paiute/Southwest requested that the form include guidance on PHMSA's policy and expectations for such reports and how they are to be submitted.

PHMSA response: PHMSA does not consider it appropriate to provide additional guidance for this requirement. Such guidance would likely become an additional de facto criterion and incidents of significance that do not conform to the guidance would likely not be reported. PHMSA does not want to imply that operators should not report any incident that they regard as significant, i.e., that they conclude is of sufficient importance that the regulator should be notified. Such incidents are to be reported using Form F 7100.1 in the same manner as any other incident.

C. Incident Report Form PHMSA F 7000—1, Accident Report—Hazardous Liquid Pipeline Systems (Impacted Information Collection: OMB 2137-0047)

General Comments

Substitute form: API stated that the hazardous liquid pipeline industry would prefer that PHMSA adopt the form used for its Pipeline Performance Tracking System (PPTS). API noted that use of the same form would reduce the administrative burden on reporting utilities and that the industry has refined the PPTS form, over time, based on lessons learned from the data.

PHMSA response: PHMSA appreciates the value of API's PPTS and has sought to adopt its concepts, breakdowns, and terminology to the extent practicable. However, PHMSA cannot simply adopt the PPTS form for use by hazardous liquid pipeline operators. Indeed, doing so would frustrate PHMSA's objective of creating and maintaining consistency between and among the three types of accident and incident reporting forms.

Excessive change: API contended that the proposed “revisions” on control rooms and fatigue are so substantive in nature that they in effect create a new regulatory requirement for industry, that such action can only be done through the rulemaking process, and thus the proposal is inappropriate and beyond the scope of an ICR. For example, API contended that a fatigue investigation is required by the form for every accident, something that is not required by regulations at this time. As such, API stated those requirements do not meet the criterion of necessity for an ICR and are in violation of the Administrative Procedure Act requirement for notice and comment.

PHMSA response: PHMSA has the authority to request that the owners and operators of covered pipeline facilities submit information as needed to ensure compliance with the nation's pipeline safety laws. 49 U.S.C. 60117(b)(1)-(2). Indeed, hazardous liquid pipelines are a critical part of the nation's pipeline network and information on the accidents that affect those lines is vital to ensuring public safety. Congress has Start Printed Page 41514also directed PHMSA to amend its accident and incident reporting forms to require that operators provide data related to controller fatigue, Pipeline Inspection, Protection and Safety Act (PIPES Act) of 2006, Public Law 109-468, section 20, 120 Stat. 3498 (Dec. 29, 2006), and the agency is coordinating its efforts to execute that mandate with its pending rulemaking on control room management. These authorities provide ample support for all of the information sought in the proposed revision to the accident reporting form without notice-and-comment rulemaking or further delay.

Nevertheless, PHMSA has significantly reduced the level of detail required to complete the form, particularly in the area of controller fatigue, and positive answers to the remaining questions will provide information indicating that further investigation of potential fatigue issues may be warranted.

Unnecessary information: API is concerned about the addition of data elements that will not add value to analysis of accident trends. For example, they noted that reporting the method by which MOP was determined is likely to require additional research (and associated burden) while it will not provide a commensurate benefit.

PHMSA response: PHMSA agrees and has eliminated the proposed element for reporting the method by which MOP was determined.

Short form: API noted that elimination of the short form (previously used for small releases) resulted in a significant increase in burden for reporting accidents involving minimal impact on the environment. They noted that many questions on the replacement form would not be relevant for a small release and that requiring completion of that form for all releases thus is a significant and unjustified increase in reporting burden. API submitted a revised version of the short form as part of their comments. API also noted that information on PHMSA's Web site concerning accident experience focuses on larger releases. API questioned whether PHMSA will use the data collected for smaller releases, for which the short form was previously used, to improve its safety programs.

PHMSA response: PHMSA will retain the short form for the same types of smaller releases as was done in the past.

Unknown cause: The Pipeline Safety Trust noted its conclusion that too many accidents have been attributed to an “unknown” cause. For that reason, the Trust recommended that PHMSA require that any report with the cause listed as “unknown” remain open and be updated every 60 days until a cause is determined or PHMSA concludes that all information has been provided and there is no way to determine a cause.

PHMSA response: PHMSA has concluded that many incidents were previously reported as “unknown” or “other” because the apparent causes did not fit cause categories on the incident report form. PHMSA expanded the number of sub-cause categories in its previous revision and has seen a decrease in the number of unknown/other reports. PHMSA has added additional sub-cause categories in this revision to attempt to further reduce the number of such reports. PHMSA will monitor incidents reported as “unknown” and will investigate as appropriate.

Reporting threshold: The Pipeline Safety Trust noted that Alaska's criteria for reporting hazardous liquid releases are more conservative than those used by PHMSA.

PHMSA response: The criteria defining an incident are established in regulation and a rule change would be needed to change them. Such an action is beyond the scope of this request.

Part A, Key Report Information

Question 2, name of operator: API suggested that the on-line reporting system automatically complete this field based on the entered operator ID, noting that this would reduce potential errors.

PHMSA response: PHMSA agrees and will implement this enhancement.

Question 4, location: NAPSR suggested that location be reported by GPS coordinates, including identification of the relevant “projection” to better define the latitude and longitude information.

PHMSA response: Latitude and longitude were included by PHMSA in the last revision of this form. We did not include this information in the pending proposed revised form, but will restore the information to the final form. Industry comments on the previous revision expressed concern over requirements to specify a projection, stating that this information would not be available to many distribution pipeline operators and may be confusing. PHMSA elected at that time to omit a requirement that operators specify the projection used. Since PHMSA did not propose such a change in the September 4, 2009, notice, the requirement to report latitude and longitude is being retained as in the previous form, without a need to report projection.

Question 7, commodity spilled: API noted that the revised form adds a question concerning sulfur content of crude oil without any explanation as to why this information is needed. API contended that this information is not important to understanding an accident and that there may be proprietary or other reasons not to reveal this data. API suggested that this question be deleted unless it can be demonstrated that the information will contribute to understanding accidents or their consequences. API further suggested that the listed commodities for refined products and highly volatile liquids be grouped in a more logical fashion. NAPSR suggested that the definitions for sweet and sour crude be moved to the instructions, and also noted that the definitions leave it unclear how crude oil with between 0.5 and 2.5 percent sulfur is to be reported. The Pipeline Safety Trust also noted the gap between the concentrations designated sweet and sour.

PHMSA response: We have eliminated the “sweet” and “sour” subcategories under “Crude” because this information is of limited utility in ensuring public safety. This obviates the need to address the gap in options for percent sulfur. We have adjusted the commodity list and groupings as API suggested.

Question 7, biofuels: API commented that PHMSA has proposed collecting information concerning spills of biofuels (i.e., ethanol and biodiesel) but that the form does not provide for identification of these commodities. In fact, they noted that the form refers to 49 CFR 195.50 as the regulatory basis for required reporting and that this section does not refer to biofuels.

PHMSA response: Section 195.50 requires reporting of accidents involving “a release of * * * hazardous liquid or carbon dioxide” meeting certain criteria. Hazardous liquid is defined in 49 CFR 195.3 to include all petroleum products. PHMSA's policy for regulating transport of biofuels by pipeline was described in a policy statement published August 10, 2007 (72 FR 45002). As described more fully in that statement, any blend of biofuels with petroleum products is considered subject to the existing regulations in Part 195, including § 195.50, under the definition in § 195.3. The policy statement also notes that the statutory definition of hazardous liquids includes petroleum or petroleum products and “a substance the Secretary of Transportation decides may pose an unreasonable risk to life or property.” The policy statement goes on to explain why the Secretary has determined that ethanol is a substance that may pose an unreasonable risk to life or property. Thus, accidents involving release of Start Printed Page 41515ethanol or ethanol blends must be reported under 49 CFR 195.50. The policy statement does not explicitly address unblended biodiesel. Reporting of accidents involving pure biodiesel transported by pipelines would not be required under current pipeline safety regulations, although operators could report such releases voluntarily. PHMSA has revised the form to include biofuels and biofuels blends.

Question 8, unit of measure: API commented that use of two units of measure (barrels and gallons) has caused confusion. API suggested that data be reported only in barrels. API further suggested that if PHMSA continues to request gallons for spills of less than one barrel, that the on-line data entry should include a validation check that will prevent the use of gallons for spills of more than 41 gallons. API suggested that, in either event, data entry must allow the use of two decimal places.

PHMSA response: We have modified the form to accept only barrels as the unit of measure, and to allow for the use of two decimal places.

Questions 9 and 10, volume spilled and recovered: API commented that it is important that these questions indicate that the reported volumes are expected to be estimates.

PHMSA response: We have added the word “estimated” to each item on the form, and the instructions will also reflect this expectation.

Question 13: NAPSR suggested that this question be modified to collect the date and time of any shutdown. The Pipeline Safety Trust also suggested that an option be provided to indicate that the pipeline is still shut down, since a shutdown may extend beyond the time at which the written report must be filed.

PHMSA response: We have incorporated both of these suggestions.

Question 17, response time: API objected to the proposed restructuring of this sentence (to Elapsed Time from Operator's Awareness of Accident to Arrival of Operator Personnel on Site). They commented that “awareness” is too vague. They noted that response personnel may be a contracted oil spill response organization, as allowed by 49 CFR 194.115. They also noted that mitigating actions can begin before response personnel arrive on site, such as via SCADA commands. NAPSR suggested that this question be revised to collect a time sequence of key events such as when the operator was notified, when operator personnel arrived on site, and when the area was made safe. Other commenters noted that the form and instructions were not consistent for this question.

PHSMA response: We have revised this question to request a time sequence as NAPSR suggested. We have made a similar change to the other incident/accident report forms. We have also revised the time line elements to clarify our intent.

Part B, Additional Location Information

Question 21, nearest address: API noted that determining a valid address can be difficult for rural locations. They further noted that the latitude and longitude information reported in question 4 will adequately describe the location of an accident and suggested that question 21.a be deleted.

PHMSA response: PHMSA agrees and has deleted the nearest address information from the form.

Question 22, location: NAPSR suggested adding elements for locations between station designations, segment ID, and pipeline name.

PHMSA response: Segment ID and Pipeline name have been added. PHMSA considers that “between stations” information is not needed because the Milepost, Valve, or Station number is already requested.

Question 23, Federal lands: The Pipeline Safety Trust questioned why lands in National Parks are excluded from categorization as Federal lands.

PHMSA response: This question identifies accidents that occur on pipeline rights-of-way on Federal lands authorized pursuant to 30 U.S.C. 185, and National Parks are specifically excluded from that statute.

Question 24, location: API suggested that this question refer to the location of the accident as opposed to the location of a failure. API also suggested that some of this information be relocated. In particular, they suggested that information concerning whether the incident occurred in a pipeline segment that had been identified as able to affect a high consequence area be moved to Part D, where consequences are addressed. They also suggested that questions concerning crossings (i.e., bridge, rail, and road) be presented in a separate question uniquely devoted to crossings. Finally, they would have clarified that reported water depth for accidents that occur in a body of water is expected to be approximate, since depth can vary over time. NAPSR suggested capturing the name of any body of water. The Pipeline Safety Trust suggested that an additional option was needed for water bodies to reflect those that are intermittent/ephemeral.

PHMSA response: PHMSA has adopted all of these recommendations with the exception of the last one. PHMSA concludes that recognized bodies of water will include these types of intermittent/ephemeral water flows, at least those of significance to pipeline safety.

Question 26, origin in State waters: NAPSR suggested that area, block/track number, and nearest county be required for incidents originating in State waters.

PHMSA response: PHMSA has incorporated these suggestions.

Question 27, area of failure: API again requested that the form refer to accident as opposed to failure. They also suggested a restructuring of the data elements to separate onshore from offshore and reduce the need to report as “other.” NAPSR suggested adding a space for operators to describe the water, building, or space. The Pipeline Safety Trust questioned the element for above ground but under pavement.

PHMSA response: We have incorporated these suggestions.

Part C, Additional Facility Information

Question 28, pipeline function: API noted that “gathering” and “transmission” are pipeline types and that the presence in this question of choices for tanks and facility piping could be confusing. They suggested that these additional elements be moved. They also noted that only gathering is defined in Part 195 and they suggested that the choices here should thus be “gathering” and “trunkline/transmission.”

PHMSA response: We have incorporated these suggestions.

Question 30, distance between valves: API requested that elements 30 (d) and (e) be removed. They noted that the distance between valves cannot be used to infer adequate protection without knowledge of a number of other pipeline factors, and that this issue had been previously addressed through rulemaking. They are concerned that reporting of this data will create a temptation to make meaningless comparisons and conclusions.

PHMSA response: PHMSA agrees with API that the information in parts (d) and (e) of this question would not be useful without the knowledge of a number of other factors and has removed these elements.

Question 31, item involved: API suggested addition of items and modification of others to make data entry easier and reduce reporting as “other.”

PHMSA response: PHMSA has made the suggested changes.

Question 34, type of failure: API expressed concern that reference to the type of “separation” could create Start Printed Page 41516confusion as it implies failure of a seam. They suggested that this question, instead, refer to the orientation of a failure as generally longitudinal or circumferential.

PHMSA response: PHMSA has made the suggested changes.

Part D, Additional Consequence Information

Environmental impacts: API commented that PHMSA had not included the information that was in section F.2 of the previous form on environmental impacts. Instead, API contended that PHMSA was collecting environmental impact data only for those accidents for which the release affects a high consequence area. API strongly encouraged PHMSA to continue to collect environmental impact data on all accidents.

PHMSA response: PHMSA agrees and restored these elements.

Question 35, high consequence areas: NAPSR suggested combining all of the elements for spilled commodity affecting HCAs into one question and including commodity recovered. NAPSR also suggested adding a question on whether animals or other species were affected. API recommended that questions pertaining to the amount of commodity released and recovered in an HCA be deleted. They expressed concern that this reporting could create confusion and result in multiple counting of released volume.

PHMSA response: Questions pertaining to affected animals or other species were added. The questions pertaining to volume spilled and recovered have been eliminated.

Question 36, costs: API suggested that this question acknowledge that the reported amounts are expected to be estimates. API also suggested restoring the word “reimbursed” and adding the word “paid” to the category on public or private property damages and adding an element for “other” costs. NAPSR suggested capturing costs separately for facilities directly and indirectly affected. NAPSR also suggested additional elements to capture costs related to business interruption (e.g., lost sales, tariffs, line down time). The Pipeline Safety Trust suggested that PHMSA needs to specify the price to be used to estimate the cost of lost commodity.

PHMSA response: API's suggestions have been incorporated. PHMSA believes that trying to segregate direct effects vs. indirect effects would introduce a significant element of complexity and confusion, and would not add any analytical value to the data. Also, business interruption impacts involve proprietary information which could not be revealed. The price of the commodity to be used in these estimates is highly variable and location-dependent, so it would not be feasible for PHMSA to try to specify the values to be used in all situations.

Part E, Additional Operating Information

Question 37, special regulatory treatment: API requested that this question be deleted. They questioned whether the fact that a pipeline was operating under any of the listed regulatory authorizations/restrictions at the time of an accident adds any useful information for accident analysis and trending.

PHMSA response: PHMSA has deleted this question.

Question 39, MOP: API questioned the usefulness of this information to accident analysis and suggested that the method used to determine MOP only be asked for accidents resulting from overpressurization.

PHMSA response: We reconsidered the need for this information. Experience has shown that an error in calculating MOP is rarely, if ever, relevant in determining the cause of an accident. It has also shown that such information can be more efficiently and effectively gathered during the course of an accident investigation. For these reasons, PHMSA has eliminated this question.

Question 40, overpressurization: The Pipeline Safety Trust suggested that additional information is needed concerning overpressurizations that may have been experienced in the year preceding the accident and that PHMSA should ask explicitly if the operator believes that overpressurization played a factor in contributing to the accident.

PHMSA response: Part E includes questions that ask the estimated pressure at the point of the incident, the MAOP, and the range of potential overpressure. In addition, operators would report overpressurization as the cause of an incident in Part F. PHMSA considers this sufficient information concerning potential overpressure events. This report is intended to collect information concerning an incident, and it would be inappropriate to include questions that address past operations (e.g., overpressure experiences in the preceding year). Historical operating experience that might indicate a systemic problem related to an incident would be appropriate for examination during a post-incident investigation, but such investigations are not the subject of this form.

Question 42, initial detection: API noted that the definition of controller in the pending proposed rule was too expansive and suggested that reporting here be limited to controllers as defined in API-RP-1168. They also suggested additional changes to prevent confusion within the industry.

PHMSA response: The definition of controller in the rulemaking identified by API is not at issue in this information collection request. However, PHMSA has made the additional changes API suggested.

Questions 44-57, fatigue: API objected to inclusion of these questions, noting that a rulemaking addressing this subject is still in progress. API suggested revisions and deletions to individual questions in the event PHMSA did not agree to delete them all. The suggested changes would eliminate questions that API considers subjective (e.g., whether a supervisor thought a controller was fatigued) and would reorganize questions to what API perceives as a more logical relationship. The Pipeline Safety Trust noted that question 44 does not seem to allow for the option of a determination that a controller did not cause or contribute to the accident.

PHMSA response: Consistent with a recommendation made by NTSB, Congress ordered PHMSA to obtain specific data from owners and operators on the role of controller fatigue in incidents reporting forms. Pipeline Inspection, Protection and Safety Act (PIPES Act) of 2006, Public Law 109-468, § 20, 120 Stat. 3498 (December 29, 2006). Nonetheless, PHMSA has reduced the amount of information required by these questions. The revisions allow for reporting that the facility was not monitored by controllers or that the operator determined that a review of controller actions was not needed. The revised form also allows for reporting review results that determined there were no control room/controller issues. PHMSA considers that this is the minimum information for it to satisfy the statutory requirement.

Question 58, drug and alcohol testing: API requested that this question be deleted. They contended that it provides no useful information for accident analysis and is related only to compliance. The Pipeline Safety Trust suggested that this question be expanded to include other covered employees. The Trust also suggested that operators be required to state their basis for concluding that drug and alcohol testing was not necessary, if that is the case, and to report information concerning the tests and results if tests were administered.Start Printed Page 41517

PHMSA response: Whether any operator or contractor employees were tested under DOT's post-accident requirements—and if so, how many failed—would be pertinent for any accident report. This determination provides information related to potential contributing causes. The form has been modified to require that the number of persons who failed a post-accident test, and the number that did not fail, be reported. PHMSA does not consider it appropriate to require operators to state a basis for not testing. That basis would be subject to PHMSA's review under our accident investigation process.

Integrity management and testing: NAPSR suggested that a new section be added to the end of part E to collect information concerning integrity management assessments and testing that is now addressed in several other portions of the form.

PHMSA response: Questions concerning pipeline assessment occur in multiple sections of Part F. Operators only complete one section of Part F, depending on the cause of the accident. Accordingly, the assessment questions do not result in duplication of effort. In fact, operators need not provide assessment information for causes for which assessment is not relevant. PHMSA considers it appropriate to ask these questions as part of the information related to causes for which assessment may be relevant. PHMSA has thus not collected these questions into a new section.

Part F, Cause Information

Part F, F1—Corrosion

Type of corrosion: API noted that more than one issue may be causing corrosion and suggested that the form allow for selection of multiple elements to accommodate this possibility. For internal corrosion, NAPSR suggested a question be added asking whether coupons were used.

PHMSA response: We have incorporated the suggested changes.

Cathodic protection surveys: API suggested that reference to close interval survey (CIS) or other cathodic protection surveys should be revised to refer to cathodic protection surveys of any type, thereby reducing the apparent importance placed on CIS.

PHMSA response: We have expanded and clarified the questions.

Non-destructive examinations (NDE) and assessments: API noted that the most recent NDE for many pipelines would have been done at the time of construction and that these records may be difficult to access. Accordingly, requesting information about these exams could pose significant burdens. API suggested that this data element be limited to examinations conducted since the integrity management regulations became effective at the end of 2001. According to API, this would reduce the burden to retrieve this information and would make it more useful, since reported information would reflect examination of the pipe in service instead of at initial construction. API also requested that the distinction between high resolution and standard resolution magnetic flux leakage (MFL) tools be clarified or the need to report each separately be eliminated. This comment was also made for other sections of part F.

PHMSA response: PHMSA agrees that recent NDE experience is of interest and that the effort to retrieve construction data is not necessary. We have modified the form to request NDE-related information only if an operator has performed an examination since 2001. PHMSA has also eliminated the need to differentiate between standard- and high-resolution MFL tools.

Part F, F2—Natural Forces

Thermal stress: API suggested that guidance is needed concerning the meaning and use of this term.

PHMSA response: We will revise the instructions to include guidance in this area.

High winds: API recommended that the instructions emphasize that damage from “wind- or weather-induced contact by debris or boats, barges, anchors, drilling rigs, or other objects” should be reported in this category rather than similar categories in F3 or F4.

PHMSA response: A similar question was included on the draft Gas Transmission/Gathering form. Comments submitted concerning that form suggested that secondary impacts (i.e., impact from boats, barges, etc. that might be moved by high winds) be reported as “Other Outside Force Damage.” PHMSA desires to maintain consistency among the forms as to how accident data is collected, as this will facilitate future analysis. PHMSA has modified this question to capture only incidents directly associated with High Winds, placing secondary damage such as may be caused by drifting barges under “Other Outside Force Damage” as INGAA suggested. PHMSA will ensure that guidance for reporting secondary impacts is included in the instructions.

Natural fire: API suggested eliminating reference to natural fires under temperature. They noted that a natural fire (e.g., forest fire) would likely be caused by lightning, which is a separate element in this part, and that its treatment under temperature is confusing. NAPSR suggested making forest fires a separate sub-cause.

PHMSA response: PHMSA agrees and has revised the form to collect information concerning accidents caused by fires initiated by lightning damage. Accidents resulting from man-made fires would be reported under F4, other outside force damage.

Part F, F3—Excavation Damage

Location: NAPSR suggested deleting “unknown” under damage location, since operators should know where the damage occurred.

PHMSA response: PHMSA generally includes “unknown” or “other” in data elements where operators select among available options. PHMSA agrees that operators should most likely be able to select an element from the list provided here, but has continued to provide an “unknown/other” option for any situations in which the choices provided are not sufficient.

Damage Information Reporting Tool (DIRT): API noted that the proposed form adopted many of the data elements used by the Common Ground Alliance in its DIRT system, in lieu of the information previously required for excavation damage incidents. API recommended that this change not be made. API reported its own experience with DIRT for consideration by PHMSA in case PHMSA did not agree to return to the excavation damage information previously required. API noted that it has modified its PPTS system to collect the data used in the DIRT system and that it then uploads that data directly to DIRT for all events reported to PPTS. API noted that requiring this information to be submitted to PHMSA would represent unnecessary duplication unless PHMSA also agrees to provide this information to DIRT, in which case API would cease collecting this data for PPTS. API recommended that PHMSA collect only that data identified in DIRT as mandatory. NAPSR suggested additional data elements for inclusion.

PHMSA response: The Common Ground Alliance (CGA) is the recognized authority for preventing excavation damage of underground utilities. The CGA has determined the information necessary to evaluate excavation damage trends via its DIRT system. PHMSA has adopted in this form the fields defined within the DIRT system as mandatory. Collecting information on excavation damage consistent with DIRT will allow for thorough analyses to identify trends related to excavation damage. It will Start Printed Page 41518also allow comparative analyses to consider information reported to DIRT by other underground utility operators, thereby expanding the database and potentially affording additional insights.

Part F, F4—Other Outside Force Damage

Vehicular damage: API suggested that the element concerning damage by a vehicle or other equipment be modified to include damage by the operator or its contractor. NAPSR suggested adding sub-elements to identify if barriers were in place, the distance between the roadway and the facility, and the location of damaged facilities.

PHMSA response: PHMSA modified this question to collect information as to whether the vehicle was operated by operator or operator contractor personnel. PHMSA did not include questions concerning vehicle barriers. Experience shows that unique circumstances are often involved in vehicle-damage accidents, making it difficult to develop a uniform set of questions that would collect the appropriate information in all cases. The presence and location of vehicle barriers is more appropriately addressed as part of an accident investigation.

Assessment: API questioned the value of collecting data on when inspection tools were run, noting that damage could have occurred subsequent to an inspection. API suggested that this element be replaced with a question asking whether the operator has reason to believe that its most recent internal inspection was completed prior to the damage being sustained.

PHMSA response: We have added the question API suggested. PHMSA also has retained the questions concerning when tools were run. PHMSA recognizes that damage could have occurred subsequent to the last tool run, but it is also possible that damage went unrecognized as a result of the type of tool used or for other reasons. PHMSA considers it important to collect information which can be used to help identify whether assessment requirements are being effective in preventing accidents from latent outside force damage.

Prior damage: API noted that the instructions should explicitly state that this section is to be completed for accidents resulting from prior excavation damage. They further suggested that a question be added as to whether the prior damage resulted from excavation. API again suggested that the questions related to assessments be limited to assessments/inspections conducted since the effective date of integrity management regulations.

PHMSA response: PHMSA added the word “mechanical” to damage, which is more accurate than stating “excavation” damage. PHMSA also added a question as to whether the prior damage resulted from excavation. PHMSA did not limit the questions to those assessments conducted since the effective date of the integrity management regulations because these sorts of preventive assessments may well have taken place prior to and without regard to whether they were required by regulations.

Part F, F5—Material and/or Weld Failure

Title: API noted that this redesigned section caused considerable confusion among its members. They suggested that the section be retitled “material failure of pipe or weld” which they believe will resolve the confusion.

PHMSA response: PHMSA has made the suggested change.

Multiple causes: API suggested that the section on cause should include more options and should allow for multiple to be selected (i.e., check all that apply).

PHMSA response: PHMSA agrees and has revised the form to indicate that multiple choices can be made.

Failure drivers: API noted that the distinction between construction and original defect is not clear. They also noted that fatigue or vibration would be a factor that would drive a construction-related or other incipient defect to failure, rather than being a cause unto itself. API suggested a restructuring to reflect this relationship.

PHMSA response: PHMSA has revised the form to indicate that sub-causes are construction-related or original manufacturing defects. PHMSA has also reorganized the form to collect information on the subsequent mechanism that likely drove one of these defects to failure.

Part F, F6—Equipment Failure

Failure methods: API indicated that the hazardous liquid pipeline industry is working hard to understand equipment failure problems. They suggested that additional data in this section would be useful, and provided an expanded list of failure methods to be included.

PHMSA response: PHMSA has revised the form to incorporate API's suggestions.

Pump failure: API noted that a motor failure cannot, alone, cause a release from a pump. API suggested that the sub-questions for this element be limited to body failure, crack in body, and appurtenance failure.

PHMSA response: PHMSA agrees and has modified the sub-questions accordingly.

Part F, F7—Incorrect Operation

Revisions: API suggested a different set of questions for this section, to better understand the causes of incorrect operation.

PHMSA response: PHMSA has incorporated the API-suggested questions.

Instructions for Form 7000-1, Accident Report—Hazardous Liquid Pipeline Systems

Inadequate instructions: API commented that the proposed instructions were inadequate, consisting for the most part of information duplicated from the form. API concluded that the extensive changes to the form, plus its applicability to operators of low-stress and rural gathering pipelines not previously subject to the regulations makes it imperative that good and thorough instructions be provided. API prepared and submitted a proposed draft set of instructions as part of their comments.

PHMSA response: PHMSA will revise the instructions to provide more guidance and to minimize repetition of information from the form.

Zero as a placeholder: The draft form instructed operators to enter unknown for text fields and “0” for numeric fields where information is unavailable. API suggested that numeric fields for which information is not available should be left blank. They noted that zero can be interpreted as actual data and that this will distort subsequent analyses.

PHMSA response: PHMSA agrees and will revise the instructions to so indicate.

Required fields: API noted that there is no indication on the draft form as to which fields are required. They also commented that the on-line data entry option does not indicate which fields are required until after data entry has been completed.

PHMSA response: PHMSA has held several discussions with Trade Association teams on general form design. Feedback from various stakeholders will be taken into account for both hard copy and electronic form design, including consideration of which fields are required for both instances.

Volume recovered: API requested that the instructions include guidance for estimating the amount of a spill that is recovered.

PHMSA response: PHMSA will include such guidance in instructions.Start Printed Page 41519

Guidance on costs: API requested that the instructions include explicit guidance for how costs related to an accident are to be estimated. The proposed instructions API submitted included such guidance.

PHMSA response: PHMSA will include such guidance in instructions.

Conflicts with regulations: The Pipeline Safety Trust suggested that there were conflicts between the instructions and the regulations concerning the definition of highly volatile liquids and treatment of natural gas liquids.

PHMSA response: PHMSA will address conflicts between the instructions and the regulations concerning the definition of highly volatile liquids and treatment of natural gas liquids in revisions to instructions that will be posted in the docket at time of publication of this r notice.

Fatality: The Pipeline Safety Trust objected to the instructions that a fatality occurring more than 30 days after an accident as a result of an injury incurred from the accident should be reported as an injury. They contended that all fatalities resulting from an accident should be reported as a fatality.

PHMSA response: This distinction is standard DOT practice. PHMSA acknowledges the logic behind attributing any resulting fatality to an accident, but there are practical difficulties in doing so. Accidents may result in injuries that subsequently contribute to death, sometimes long after the injury occurs. PHMSA cannot require pipeline operators to maintain contact with injury victims so that they will be aware of subsequent deaths and can modify incident reports accordingly. Thus, it is necessary to have some practical time limit in which operators would be expected to have this information and in which it is relatively clear that the accident is the proximate cause of death. PHMSA has no reason to deviate from DOT standard practice in establishing this limit.

Comments on Burden Estimate, Form 7000-1, Accident Report—Hazardous Liquid Pipeline Systems

Basis for estimates: API noted that PHMSA's basis for the number of forms to be completed each year is based on the historical record of number of accidents reported. API considered this inaccurate, since a recent change to the regulations has made the regulations applicable to additional pipeline mileage (low-pressure pipeline and rural gathering lines between 6 and 8 inches in diameter). API also noted that the burden estimate included the short form, which was eliminated in this ICR. API reported its conclusion that the estimate of seven hours to complete the form is significantly low.

PHMSA response: PHMSA has restored a short form to be used for small releases. PHMSA acknowledges that more accident reports may be filed in the future as a result of additional pipeline mileage made subject to Part 195. At the same time, other regulatory (and voluntary) initiatives have been put in place that are intended to significantly reduce the number of accidents that occur. If those initiatives are successful, then use of the historic record could actually overestimate the number of reports that will be submitted in the future. It is not possible to know which outcome will occur, and PHMSA considers that use of the historical record is most appropriate.

III. Proposed Information Collection Revisions and Request for Comments

The forms to be revised are pipeline accident and incident reporting forms authorized by Information Collections OMB 2137-0522, Incident and Annual Reports for Gas Pipeline Operators and OMB 2137-0047, Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting. The revised burdens hours associated with these information collections are specified as follows:

Title of Information Collection: Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting.

OMB Control Number: 2137-0047.

Type of Request: Revision of currently approved information collection.

Abstract: Currently Information Collection 2137-0047 entitled “Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting” has an approved burden hour estimate of 51,011 hours and 200 respondents. This information collection consists of a broad scope data collection relative to hazardous liquid pipeline operators. This notice will affect only a portion of this information collection for accident reports. PHMSA estimates that the currently approved 200 respondents for this information collection should be revised to 300 respondents. This 100 respondent increase reflects the number of smaller entities that were previously unaccounted for due to the fact that they did not have to pay user fees and were not inspected by PHMSA. Therefore, this group became recognized after we began collecting annual reports in 2004. PHMSA estimates that 150 accident reports are submitted each year. This estimate is based on accident reporting data that PHMSA has collected over the past decade (1999—2008). Currently, PHMSA estimates that each form takes an estimated 6 hours to complete. This sets burden hours relative to completion of the accident form at 1,200 hrs. (200 responses * 6 hours/response). PHMSA estimates that the form changes relative to this notice will result in a 2 hour increase in the amount of time necessary to complete an accident report. However, since we estimate that 150 accident reports are submitted each year versus 200 accident reports this 2 hour increase in time will result in no change to the total annual burden hours (200 * 6 = 150 * 8). The amendments specified above will result in the following:

Affected Public: Natural Gas and Hazardous Liquid Pipeline Operators.

Recordkeeping

Estimated Number of Respondents: 300.

Estimated Total Annual Burden Hours: 51,011 hours (no increase).

Frequency of collection: On occasion.

Title of Information Collection: Incident and Annual Reports for Gas Pipeline Operators.

OMB Control Number: 2137-0522.

Type of Request: Revision of currently approved information collection.

Abstract: Currently Information Collection 2137-0522 entitled “Incident and Annual Reports for Gas Pipeline Operators” has an approved burden hour estimate of 36,105 hours and 2,100 respondents. This information collection consists of incident and annual reporting for gas pipeline operators. PHMSA's approved 2137-0522 information collection estimates that 10 percent (210) of the respondent community (distribution and transmission operators) will submit an incident report. Upon review of recent annual and incident report data, PHMSA estimates the respondent community at 2,212 respondents (950 Transmission Operators and 1,262 Distribution Operators). Also, PHMSA has reviewed the past 10 years of incident data (1999—2008) and is revising the estimated 210 incident reports/year to an estimated 300 incident reports/year. PHMSA estimates that the current form will takes 6 hours to complete. This sets the current burden hours relative to completion of the incident form at 1,260 hrs. (210 responses * 6 hours/response). PHMSA estimates that the form changes relative to this notice will result in a 2 hour increase in the amount of time necessary to complete an incident report. This adjustment, along with the other amendments specified above, will increase the estimated burden hours Start Printed Page 41520relative to incident forms from 1,260 hours to 2,400 hours (300 responses * 8 hours/response). This will increase the total estimated burden hours from 36,105 hours to 37,245 hours. The result of this revision is specified as follows:

Affected Public: Gas Pipeline Operators.

Recordkeeping

Estimated Number of Respondents: 2,212.

Estimated Total Annual Burden Hours: 37,245 hours (1,140 hour increase).

Frequency of collection: On occasion.

Comments are invited on:

(a) The need for the proposed collection of information for the proper performance of the functions of the agency, including whether the information will have practical utility;

(b) The accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;

(c) Ways to enhance the quality, utility, and clarity of the information to be collected; and

(d) Ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques.

Start Signature

Issued in Washington, DC on August 10, 2009.

Jeffrey D. Wiese,

Associate Administrator for Pipeline Safety.

End Signature End Supplemental Information

Footnotes

1.  Reportable events are referred to as “incidents” for gas pipelines, 49 CFR § 191.3, and “accidents” for hazardous liquid pipelines, 49 CFR 195.50. An operator may also be required to file a supplemental report in certain circumstances.

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2.  Question numbers used in this notice refer to the numbers on the draft forms about which comments were submitted.

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[FR Doc. E9-19499 Filed 8-14-09; 8:45 am]

BILLING CODE 4910-60-P