2137_0522_Supporting Statement_07.23.07c

Department of Transportation

Pipeline and Hazardous Materials Safety Administration

SUPPORTING STATEMENT

Natural Gas Distribution Incident and Annual Report Forms

Docket No. PHMSA-98-4957

INTRODUCTION

The Pipeline and Hazardous Materials Safety Administration (PHMSA) requests approval from the Office of Management and Budget (OMB) for an extension and medication of a currently approved collection of gas pipeline information (OMB Control No. 2137-0522), which was approved on 04/30/2004. The collection expired on 04/30/2007.

PHMSA requires each gas pipeline operator to submit incident and annual reports on distribution, transmission, and gathering pipelines (49 CFR Part 191). PHMSA also requires each operator to provide immediate telephone notification when a potentially significant safety incidents occurs (49 CFR § 191.5). Operators then are required to send a follow-up report for each incident within 30 days of the incident (49 CFR § 191.9 and §191.15). The operators use forms PHMSA F 7100.1, F 7100.2, F 7100-1.1, and F 7100-2.2 for their report submissions to PHMSA (Attachment 1).

These reports help PHMSA identify and evaluate potential pipeline safety problems to minimize natural gas pipeline failures. PHMSA normalizes the incident information data for safety trend analysis (normalizing is the process of making elements of data comparable for comparison purposes). PHMSA’s top priorities are to better utilize data to identify safety problems and to adopt enterprise approaches with federal, state, local, industry and public stakeholders to build effective solutions and achieve the best possible safety performance.

Part A. Justification

1. Circumstances that make collection of information necessary – Identify any legal or administrative requirements that necessitate the collection. Attach a copy of the appropriate section of each statute and regulation mandating or authorizing the collection of information:

Gas pipeline releases can cause human injuries, fatalities, economic losses, and environmental damage. Rapid reporting, detailed incident reports, and annual summary reports all help to inform PHMSA and the public of release incident risks and trends. The National Transportation Safety Board (NTSB), the U.S. Department of Transportation’s Office of the Inspector General, and the General Accounting Office all urged PHMSA to collect this information. The information is an essential part of PHMSA’s overall effort to minimize natural gas transmission, gathering, and distribution pipeline failures.

The requirements for reporting incidents are in 49 CFR Part 191 (Attachment 2). The legislative authority for the requirements in 49 CFR Part 191, as identified in the attachment, is at 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, and 60124. Additional authority for the requirements is at 49 CFR 1.53.

The definition of a pipeline incident is any of the following events:

1. Injury or Damage - An event involving a release of gas from a pipeline or of liquefied natural gas or gas from an LNG facility and either a death, personal injury necessitating hospitalization, or $50,000 or more in property damage to the operator or others;

2. Emergency Shutdown - An event resulting in an emergency shutdown of an LNG facility, or,

3. Significant - An event that is significant in the operator’s judgment, regardless of the other criteria.

Telephonic Notice of Certain Incidents (Section 191.5)

Each gas pipeline operator must provide telephonic notice of an incident at the earliest practicable moment following discovery. Telephonic notification enables PHMSA’s enforcement division to send investigative personnel to the scene of the incident to determine any noncompliance with pipeline safety regulations. Prompt telephonic notification of an incident allows the enforcement division to quickly initiate corrective measures to prevent avoidable personal injuries and fatalities, or damage to the pipeline and the environment.

Incident Reports for gas distribution systems (Section 191.9) and gas transmission and gathering systems (Section 191.15)

Gas pipeline operators are required to submit an incident form within 30 days after a detecting an incident. The reports are necessary to identify and evaluate existing and potential pipeline safety problems and perform safety trend analysis. In addition, this information collection is essential to respond to queries from Congress, and to supply information for the Federal Energy Regulatory Commission (FERC) as specified in 18 CFR 260.9(d).

Annual Reports for gas distribution systems (Section 191.11) and gas transmission and gathering systems (Section 191.17)

The gas pipeline operators are required to submit annual reports to PHMSA that aggregate all the safety related information over the past calendar year. This information collection is necessary to prepare the biennial report to the Congress mandated by 49 U.S.C. 60124, which must include a compilation of leak repairs, pipeline accidents, and casualties.

The information collection associated with this renewed regulation will promote the US DOT’s Safety and Environmental Strategic Goals. Standardized data on the pipelines assists PHMSA with risk identification and mitigation to reduce the frequency and severity of pipeline incidents. The resulting decrease will improve human and environmental resources protection.

2. How, by whom, and for what purpose is the information used – Indicate how, by whom, and for what purpose the information is to be used. Except for a new collection, indicate the actual use the agency has made of the information received from the current collection:

Pipeline operators will contact PHMSA immediately following pipeline incidents meeting the definition above. In addition, the operators must submit reports for every gas distribution/transmission and gathering pipeline incident and annual reports on an annual report form. The annual report form has query fields regarding incident cause categories, impacts, failure mechanisms, locations, and other details about natural gas pipeline incidents. PHMSA uses the information to track incidents and help guide future regulations to reduce future pipeline incidents.

PHMSA uses immediate telephonic notification (Section 191.5) to address ongoing safety issues related to an incident. The individual reports, for each incident (Sections 191.9 and 191.15) enable PHMSA to identify and evaluate existing and potential pipeline safety problems and perform safety trend analyses. The information is also essential for FERC reporting compliance.

The annual reports for gas distribution/transmission and gathering (Sections 191.11 and 191.17) are used for identifying existing or potential pipeline safety problems, to develop statistical and data/safety reports, and to develop benefit-cost analyses pertaining to pipeline safety.

Without the information collection, PHMSA would not be guaranteed timely notification of gas pipeline incidents, would lack the ability to track safety, and would lack a method to proactively identify trends and avoid potential safety issues.

3. Extent of automated information collection – Describe whether, and to what extent, the collection of information involves the use of automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g. permitting electronic submission of responses, and the basis for the decision for adopting this means of collection. Also describe any consideration of using information technology to reduce burden:

Pipeline operators are encouraged to file the incident and annual reports on-line, except in cases of imminent danger. In 2006, 55 percent of pipeline operators submitted annual reports electronically. PHMSA expects the proportion of electronic versus paper filings will increase.

4. Efforts to identify duplication – Describe efforts to identify duplication. Show specifically why any similar information already available cannot be used or modified for use for the purposes described in item 2 above:

PHMSA is the only federal agency that collects information related to distribution pipeline failures. No similar information is requested by the government or industry on distribution pipeline failures that occur between the point-of-sale to a distribution company and a customer’s meter.

The information collection on gas transmission and gathering pipelines is extremely limited in terms of scope and population of gas pipeline operators covered. The Department of Interior (DOI) collects information that is in some ways similar to that collected by PHMSA, but the information DOI collects does not cover all gas transportation or gathering pipelines.

Operators are only required to submit one annual report for gas pipelines. Incidents will show up on both the incident form and the annual report. This duplication is necessary as PHMSA needs to be alerted immediately about incidents to respond to them, and at the year close to summarize the total number of incidents.

5. Efforts to minimize the burden on small businesses – If the collection of information impacts small businesses or other small entities (Item 5 of OMB Form 83-1), describe any methods used to minimize burden:

PHMSA expects impacted operators to be large and small businesses and therefore the requirement may impact small businesses and other entities.¹ However, since this information collection currently exists, operators have presumably planned for these reporting requirements and made the necessary adjustments to their personnel and budgets. For PHMSA to be able to effectively carry out its legislative mandate and monitor natural gas pipeline safety, it is essential that both large and small operators of pipelines provide incident and annual reports.

6. Impact of less frequent collection of information – Describe the consequence to Federal program or policy activities if the collection is not conducted or is conducted less frequently, as well as any technical or legal obstacles to reducing burden:

PHMSA would not be able to assess the rate and locations of incidents to the gas distribution/transmission and gathering pipelines without the proposed information collection. Lack of telephonic notification may increase the risks to people and property if the release is ongoing. The biennial report to Congress mandated by 49 U.S.C. 60124(b) would not have current information without the annual reports. Less frequent information collection could compromise the safety and economic viability of the U.S. pipeline system.

7. Special circumstances – Describe any special circumstances that would cause an information collection to be conducted in a manner:

• Requiring respondents to report information to the agency more often than quarterly;

• Requiring respondents to prepare a written response to a collection of information in fewer than 30 days after receipt of it;

• Requiring respondents to submit more than an original and two copies of any documents;

• Requiring respondents to retain records, other than health, medical, government contract, grant-in-aid, or tax records for more than three years;

• In connection with a statistical survey, that is not designed to produce valid and reliable results that can be generalized to the universe of study;

• Requiring the use of a statistical data classification that has not been reviewed and approved by OMB;

• That includes a pledge of confidentiality that is not supported by authority established in statute or regulation, that is not supported by disclosure and data security policies that are consistent with the pledge, or which unnecessarily impedes sharing of data with other agencies for compatible confidential use; or

• Requiring respondents to submit proprietary trade secret, or other confidential information unless the agency can demonstrate that it has instituted procedures to protect the information’s confidentiality to the extent permitted by law.

There are two anticipated potential special circumstance regarding information collection with this renewal. First, operators having more than one reportable incident or accident within an officially recognized business quarter would have to file an incident report for each. Second, an operator may have one or more reportable incidents or accidents in the same quarter that their annual report is due. Operators, through their safety measures and vigilance, can avoid such circumstances. As such, PHMSA is not mandating information collection occur twice within a single quarter.

8. Compliance with 5 CFR 1320.8 – Provide an electronic copy and identify the date, volume number and page number of the publication in the Federal Register of the agency’s notice (For a 60-day and a 30-day Notice), required by 5 CFR 1320.8(d), soliciting comments on the information collection prior to submission to OMB:

On February 12, 2007 PHMSA published a Federal Register (FR) notice requesting comments on the information, providing a 60-day comment period (72 FR 6664). PHMSA received three comments from the 60-day FR notice. The comments are presented below:

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Commenter: Kristine J. Nichols, Vice President Engineering, Nicor Gas

Date: April 12, 2007

Northern Illinois Gas Company d/b/a Nicor gas Company (Nicor) is a local distribution company (LDC) that operates an integrated transmission and distribution system to distribute natural gas to over 2.2 million customers in northern Illinois, with the exception of the city of Chicago and some surrounding suburbs. Nicor operates 1,195 miles of intrastate transmission pipeline and 32,671 miles of distribution pipeline. Nicor appreciates the opportunity to comment on PHMSA’s request for comments on ways to minimize the burden associated with the collection of information related to incident and annual reports completed by gas pipeline operators.

Nicor recognizes PHMSA’s previous efforts to enhance both the incident report and annual report forms. The revisions made to the incident and annual report forms and instructions, in general, improved clarity and allowed for easier identification of incident cause trends and for evaluations of pipeline operator performance. However, Nicor believes that both the incident and annual report forms can be further enhanced to make them more meaningful and useful to operators and regulatory agencies and offers the following comments.

Practical Utility of the Information

PHMSA requested comments on whether the information collected will have practical utility. Overall, the information requested is relevant, practical, and useful. However, there are several sections of the reports that do not appear to provide value.

Annual Report Gas Distribution System Form PHMSA F7100.1-1(12-05)

• Part B, Section 1 requires operators to determine whether steel mains and services are cathodically protected or unprotected, then to further break down each category into bare or coated. For cathodically protected systems, Nicor has records to differentiate between coated and bare pipe. However, information on coating for unprotected pipeline does not seem practical at the national level form the stand point that some operators have very old systems where all that is known regarding the cathodic protection is whether the main is protected or not protected. It is not likely PHMSA could ever draw any conclusions from such historic data.

• Part B, Section 3 asks for the average service length. This information does not appear to be useful or practical.

• Part C, asks for the total leaks eliminated/repaired during the year for both services and mains. Additionally, it asks for the number of known system leaks at the end of each year scheduled for repair. Repair practices and classification procedures differ at each utility, so reporting on leaks repaired or scheduled is an inconsistent metric. It would be more appropriated to report only those leaks that are classified as hazardous since that is the only consistent definition of a leak. The reporting of all other leaks scheduled for repair is not useful for determining national averages.

• Part E, asks for the percent of unaccounted-for gas. The term “unaccounted-for gas does not always indicate a leak and therefore is not a good indicator of system integrity. The study by the by the American Gas Foundation titled “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure issued in January 2005 reached the same conclusion. In Appendix M, Section 4 (Considerations and Qualifications), item 6 of this study, the following conclusion was reached:

“Previous studies done by the Gas Technology Institute and as an result of a 2004 AGA Benchmarking study involving 5 years of data have shown that the predominant amount of unaccounted for (UAF) gas experienced by operators is due to measurement inaccuracies and accounting errors, not gas leakage from the system. Most distribution sales meters are not temperature-compensated, whereas virtually all distribution purchase meters do compensate for temperature. This creates a positive bias for UAF since more gas is sold when ambient temperatures are below the standard measurement temperature of 60 degrees F. Further, since instructions for RPSA Form F 7100.1-1 do not specify what should be included under the appropriate adjustments” factor in the % of unaccounted for gas formula, it becomes impossible to extract the gas lost through leakage to the atmosphere. As such, the % unaccounted for gas data from the DOT reports appears not to be a useful indicator.”

Incident Report Gas Distribution System Form PHMSA F7100.1 (03-04)

• Part F4 Other Outside Force – Fire/explosion as primary cause of failure: It is apparent that Part F4 requires operators to report failures where fire/explosion was the primary cause of failure. That is, the fire/explosion occurred prior to failure of the gas facilities and not as a result of the failure of the gas facilities. However, PHMSA should provide clarification on how to determine the reporting monetary threshold for fire-first incidents.

• The instructions that were in place prior to March of 2004 for completing the incident report were very clear that the $50,000 threshold for reporting applied only for damage to facilities subject to 49 CFR 192. However, the following paragraph in the prior instructions was removed from the revised instructions which took effect in March 2004.
  “Damage from secondary ignition need not be reported unless the damage to facilities subject to Part 195 exceeds $50,000. Secondary ignition is a gas fire where the cause is unrelated to the gas facilities such as electrical fires, arson, etc.”

• The lack of clarity has caused inconsistent reporting. Some utilities report fire-first incidents where jurisdictional facility-only damage exceeds $50,000 The result is skewed data. Data integrity would be improved if PHMSA reintroduced the clarification that fire-first incidents should be reported when jurisdictional facilities are damaged beyond $50,000.

Accuracy of Estimated Burden on Respondents

Based on 2,100 respondents, PHMSA has estimated the total annual burden on operators for completing incident and annual reports is 17.2 hours per respondent. Based on Nicor’s experience, this estimate appears to be low. The following is Nicor’s estimated time for completing each annual and incident report. The time includes time for data gathering, data quality review, and completing the report.

Annual Report – Distribution: 35-40 hours

Annual Report – Transmission: 3 hours

Incident Report – Distribution: 8 hours (in 2006 Nicor

telephonically reported 13 incidents to NRC, rescinded 2 reports after subsequent investigation and submitted 1 online reports to PHMSA)

Incident Report – Transmission 8 hours

It is also important to note that States may also require an additional incident report and field investigation. This is the case in the State of Illinois. The hours above do not include the additional time required to complete the corresponding State report.

Ways to Enhance Quality, Utility, and Clarity of Information

Nicor has provided some recommended modifications above to both of these reports.

Ways to Minimize Burden of Information Collection

Defining expectations and providing clear instructions to help operators submit consistent data will provide a valuable tool for PHMSA to review trends in system integrity across the nation.

In conclusion, Nicor supports the continued submission of incident and annual reports. As mentioned above, there are some parts of the existing reports that would benefit from further review by PHMSA to improve the practical utility of the data. Additionally, with PHMSA’s upcoming Notice of Proposed Rulemaking on distribution integrity management, both the incident and annual reports should be reviewed for consistency and to eliminate duplicative reporting. Nicor welcomes the opportunity to work with PHMSA, either individually or through the American Gas Association, to help review and if necessary revise the incident and annual report forms and instructions.

Respectfully submitted,

Kristine J. Nichols

Vice President Engineering

PHMSA Response:

PHMSA is currently drafting regulatory changes that will both change the annual report forms to improve the data collection and change the definition of an incident from the $50,000 threshold The changes will appear as a provision of a separate rule-making to be published in 2007 or the first quarter of 2008. PHMSA has not heard from other operators that the associated paperwork and reporting burdens exceed the estimates. Therefore PHMSA will leave the current estimates in place until other operators voice similar concerns about the burden hours calculation.

Commenter: Douglas M. Schneider, Pipeline Integrity Manager, SDGE

Date: April 12, 2007

Text:

Dear Pipeline and Hazardous Materials Safety Administration:

In reference to the February 12, 2007 notice that was published in the Federal Register by the Pipeline and Hazardous Materials Safety Administration (PHMSA) / Office of Pipeline Safety (OPS) that invites comments, “… on ways to minimize the burden associated with collection of information related to natural gas pipelines operator’s reports…”, Southern California Gas Company and San Diego Gas & Electric offer the following comments for your consideration.

Southern California Gas Company (SoCalGas) is a regulated natural gas distribution utility serving most of central and southern California through more than five million meters. As the nation’s largest natural gas distributor, we serve residential=, commercial, and industrial customers as well as electric generation and wholesale customers in a service territory that covers 20,000 square miles. San Diego Gas & Electric (SDG&E) is a regulated electric and natural gas distribution utility that spans 4,100 square miles and provides natural gas service to San Diego County through more than 800,000 meters. Together, we operate over 4,000 miles of gas transmission pipeline and have an integrity management program in accordance with the requirements contained in 49 CFR Part 192, Subpart O.

Southern California Gas Company and San Diego Gas & Electric support the need for PHMSA/OPS to collect information necessary to ensure compliance with various requirements. However, with regard to the reports required in 49 CFR Part 191 and 49 CFR Part 192 Subpart O, we believe there is an opportunity to minimize the burden of the collection of this information on respondents as well as to enhance the quality, utility and clarity of the information collected.

With regard to the incident reports, we believe that the reporting criteria should be modified to ensure that the data gathered accurately reflects incident trends over time and specifically, we believe the linkage to the cost of gas should be removed form the criteria for reporting an incident. Currently, the definition of an incident in 49 CFR 191.3 includes, in part, an event where natural gas is released and “…estimated property damage, including cost of gas lost, of the operator others, or both,…” is $50,000 or more. The “cost of gas” can vary dramatically over time, as well as costs of property, etc. As a result, over time, trends tied to numbers of “reportable incidents” may become less meaningful as changes in the number of incidents reported are impacted by cost factors rather than a change in operating conditions an/or severity of the incidents. In fact operators may be reporting more or fewer incidents, and filing the related reports, simply because the costs have changed. Ideally, we believe the reporting criteria should not be tied to the “cost of gas lost” and suggest that perhaps, a measure related to the “volume of gas lost” would be more a more consistent measure across time, along with a property damage threshold that is adjusted periodically, perhaps every five years, to reflect cost inflation and other related factors.

In reference to the annual reports containing system information, we recommend that a consistent definition of terms be adopted for the Annual Report for Gas Distribution Systems (7100.1-1), the Annual Report for Gas Transmission & Gathering Systems (7100.2-1) and the transmission integrity management reports (as required under 49 CFR Part 192, Subpart o). Doing so would greatly minimize confusion and facilitate data analysis. In addition, we suggest that the filing date of the annual transmission integrity management report coincide with, or follow, the filing date of the Annual Report for Gas Transmission & Gathering Systems (7100-2-1) as data from this report (7100.2-1) is required to complete the integrity management (IMP) reports, where the annual reports are operator specific, we strongly encourage PHMSA/OPS to continue to allow related operators to file together with one set of performance measures should they so choose. Lastly, we suggest that consideration be given to eliminating the “semi-annual” reporting requirement contained in 49 CFR 192.945 and thus reduce the burden associated with filing the “interim” IMP performance report covering the period January 1 through June 30, as the same data would be included in the report.

Thank you for the opportunity to submit comments concerning this collection of information related to natural gas pipeline operators’ reports. We look forward to continuing our work with the Pipeline and Hazardous Safety Administration and other key stakeholders in addressing the best ways to address the overall collection of information.

Respectfully submitted,

Douglas M. Schneider, P.E.

Pipeline Integrity Manager

Gas Engineering

PHMSA Response:

PHMSA is currently drafting regulatory changes that will both change the definition of an incident from the $50,000 threshold and move the semi-annual report collection into the annual reports. The changes will appear as a provision of separate rule-making process to be published in 2007 or the first quarter of 2008.

Commenter: Edward C. McMurtrie, Vice President/General Manager, Piaute Pipeline Company

Date: April 13, 2007

Text:

Dear Ms. Herrick:

Paiute Pipeline Company (Paiute) herein responds to the Pipeline and Hazardous Materials Safety Administration (PHMSA) request for public comments and Office of Management and Budget (OMB) approval for the renewal of an existing PHMSA information collection as outlined in 72 Federal Register (FR) 6664, published on February 12, 2007. The notice requests comments on ways to enhance the quality, utility, and clarity of the information to be collected and to minimize the burden of collection of information on respondents, including the use of automated collection techniques or other forms of information technology.

Paiute operates 856 miles of transmission pipeline in the state of Nevada. It is a wholly owned subsidiary of Southwest Gas Corporation (Southwest), which is a member of the American Gas Association. Paiute herein supports the comments submitted by Southwest for this docket. This letter focuses on minimizing the burden on respondents to collect certain information, including the use of automated techniques or other forms of information technology.

Paiute submits several types of periodic reports to PHMGS pursuant to the requirements of Title 49 Code of Federal Regulations (CFR), Parts 191 and 192, which include individual reports for transmission incidents (191.15); annual reports for transmission system data due on or before March 15 for the preceding year (191.17); and semi-annual reports on four overall integrity management performance measures complete through June 30 and December 31 of each year and submitted within two months after those dates (192.945).

Section 15 of the “Pipeline Inspection, Protection, Enforcement and Safety Act of 2006” requires PHMSA to address incident reporting issues no later than December 31, 2007. PHMSA is required to review the incident reporting requirements for operators of natural gas pipelines and modify the reporting criteria as appropriate to ensure that the incident data gathered accurately reflects incident trends over time, taking into consideration the recommendations contained within GAO-06-946, Natural Gas Pipeline Safety (September 2006). Paiute will be submitting comments when the Notice of Proposed Rulemaking is published that will help provide clarity and uniformity to the reporting criteria for incidents on transmission systems.

Paiute believes that the mid-year (June 30) integrity management report has little or no value since it is replaced by the December 31 semi-annual integrity management report (see 49 CFR 192.945). The June report, considered an “interim report,” is essentially superseded by the December report, which includes the annual transmission system data from the end of the previous year, which may not reflect the actual transmission data at the end of the reporting period.

The December report requests annual data as of the end of the reporting period. However, system annual report data may not be available by the filing date of the December 31 integrity management report (two months after the end of the reporting period; i.e., February 28). The integrity management report is filled 15 days before the system annual data report (due March 15 pursuant to 49 CFR 191.17) and relies upon some of the data to be submitted in that report.

Therefore, Paiute suggests that the semi-annual reports be eliminated and that the submittal data for the annual integrity management report coincide with the March 15 date for annual transmission report submittals.

Paiute appreciates the opportunity to submit its comments on this request for public comments.

If you have any questions, please contact Jeff Maples by telephone at (775) 887-2805 or by email at [email protected].

Sincerely,

Edward C. McMurtrie

Vice President/General Manager

PHMSA Response:

PHMSA is currently drafting regulatory changes to move the semi-annual report collection into the annual reports. The change will appear as a provision of a speparte rule-making process to be published in 2007 or the first quarter of 2008.

PHMSA published a notice in the FR on April 30, 2007 (72 FR 21319) notifying the public that the PHMSA forwarded the request for an extension of the information collection to OMB. PHMSA provided an additional 30 day for comments and invited the public to send comments directly to OMB Office of Information and Regulatory Affairs, Attn: Desk Officer for the Department of Transportation, 725 17^th Street, NW, Washington, DC 20503. No comments on the 30-day FR notice were received.

9. Payments or gifts to respondents – Explain any decision to provide a payment or gift to respondents, other than enumeration of contractors or grantees:

Not applicable.

10. Assurance of confidentiality – Describe any assurance of confidentiality provided to respondents and the basis for the assurance in statute, regulation, or agency policy:

Not applicable.

11. Justification for collection of sensitive information – Provide additional justification for any questions of a sensitive nature, such as sexual behavior and attitudes, religious beliefs, and other matters that are commonly considered private. This justification should include the reasons why the agency considers the questions necessary, the specific uses to be made of the information, the explanation to be given to persons form whom the information is requested, and any steps to be taken to obtain their consent:

Not applicable.

12. Estimate of burden hours for information requested – Provide estimates of the hour burden of the collection of information. The statement should:

• Indicate the number of respondents, frequency of responses, calculation for the individual burdens and for the total annual hour burden, and an explanation of how the burden was estimated. Unless directed to do so, agencies should not conduct special surveys to obtain information on which to base hour burden estimates. Consultation with a sample (fewer than 10) respondents is expected to vary widely because of differences in activity, size, or complexity, show the range of estimated hour burden, and explain the reasons for the variance. Generally, estimates should not include burden hour for customary and usual business practices

• If this request for approval covers more than one form, provide separate burden hour estimates for each form and aggregate the burden hours in items 13 of OMB Form 83-I.

• Provide estimates of annualized cost to respondents for the hourly burdens for collections of information, identifying and using appropriate wage rate categories. This cost contracting out or paying outside parties for information collection activities should not be included here. Instead, this cost should be included in item 14.

The original regulation estimated that there are 2,100 operators of natural gas pipelines submitting 2,880 annual reports and 210 incident reports annually. The total burden hours associated with the expiring regulation was 41,405. The total estimated burden hours are 36,105. Overall, the renewal is estimated to reduce burden hours by 5,300.

Telephonic Notice of Certain Incidents (Section 191.5)

Based on past estimates, there was an annual average of 570 telephonic reports. PHMSA estimates that these reports are estimated to require 30 minutes for operators to complete. The total time is expected to be 285 hours (= 570 reports x 0.5 hours).

Incident Reports for gas distribution systems (Section 191.9) and gas transmission and gathering systems (Section 191.15)

As estimated in the past, natural gas incidents on distribution/transmission and gathering lines are still estimated to occur at the annual rate of one for every ten operators. PHMSA expects the number of annual incidents will be 210 (= 0.1 x 2,100 operators). Past analysis estimates that incident reports require 6 hours to complete. The burden hours will be 1,260 hours (= 210 incidents x 6 hours). One commenter, during the comment period, stated that the estimated time for incident reports is too low. The comment was responded to in Question # 8 of this Supporting statement and will be addressed further in a subsequent initiative associated with the Pipeline Inspection, Protection, Enforcement and Safety (PIPES) Act of 2006. PHMSA believes that the majority of operators has fully integrated the reports into their incident response and are able to accomplish the reporting within the estimated time frames.

Annual Reports for gas distribution systems (Section 191.11) and gas transmission and gathering systems (Section 191.17)

Annual reports are required for all 2,100 operators of both gas distribution and gas transmission & gathering pipelines. As estimated in the past, an annual report is still estimated to require 12 hours of work to complete. Past submittals reveal that there are 2,880 annual reports. Some operators have more than one pipeline system and thus are required to submit multiple annual reports. Based on the number of reports, the total burden hours for annual reports will be 34,560 hours (= 2,880 annual reports x 12 hours). Like with incident reports one commenter, during the comment period, stated that the estimated time for annual reports is too low. The comment will be addressed in a subsequent initiative associated with the Pipeline Inspection, Protection, Enforcement and Safety (PIPES) Act of 2006. Also, PHMSA believes that the majority of operators has fully integrated the reports into their operations and are able to accomplish the reporting within the estimated time frames.

13. Estimate of total annual costs to respondents – Provide an estimate of the total annual cost burden to respondents or record-keepers resulting from the collection of information. (Do not include the costs of any hour burden in items 12 and 14):

• Include a breakdown for total capital/start-up costs and operation/maintenance. The cost estimates should be split into two components: (a) A total capital and start-up cost component (annualized over its expected useful life); and (b) a total operation and maintenance and purchase of services component. The estimates should take into account costs associated with generating, maintaining, and disclosing or providing the information. Include descriptions of methods used to estimate major costs factors including system and technology acquisition, expected useful life of capital equipment, the discount rates(s), and the time period over which cost will be incurred. Capital and start-up costs include, among other items, preparations for collecting information such as purchasing computers and software; monitoring, sampling, drilling and testing equipment; and record storage facilities.

• If cost estimates are expected to vary widely, agencies should present ranges of cost burdens and explain the reasons for the variance. The cost of purchasing or contracting out information collection services should be a part of this cost burden estimate. In developing cost burden estimates, agencies may consult with a sample of respondents (fewer than 10), utilize the 60-day pre-OMB submission public comment process and use existing economic or regulatory impact analysis associated with the rulemaking containing the information collection, as appropriate.

• Generally, estimates should not include purchases of equipment or services, or portions thereof, made (1) prior to October 1, 1995, (2) to achieve regulatory compliance with the requirements not associated with the information collection, (3) for reasons other than to provide information or keep records for the government, or (4) as part of customary and usual business or private practices.

PHMSA assumes that the telephonic report would be made by an engineering manager, who is expected to cost, fully loaded, $64.75 per hour.²

Telephonic Notices:

The annual costs associated with the telephonic notices are expected to be $18,454 (= 285 hours x $64.75 per hour)

Incident Reports:

The total estimated cost of completing the incident report forms is expected to be $81,585 (= 210 incidents x 6 hours x $64.75).

Annual Reports:

The cost will is estimated at $2,237,760 (= 2,880 annual reports x 12 hours x $64.75).

The total annual estimated costs for the three components of this information collection renewal is $2,337,799 (= $18,454 + $81,585 + $2,237,760)

PHMSA does not expect there will be costs from the renewal of the regulation beyond those cited above. Presumably, operators have already made all necessary capital investments associated with the expiring regulation, and therefore will require no additional capital investments.

The present value of the aggregate costs has been calculated using 7 percent and 3 percent discount rates. The present value of the estimated annual cost, $2,337,799, over a period of 3 years using a 7 percent discount rate is $6,135,123. The present value of the estimated annual cost over a period of 3 years using a 3 percent discount rate will be $6,612,725. PHMSA assumes the fully loaded hourly cost of a senior engineer, $64.75, will remain constant over the period. Aggregate calculations are limited to a three year time period, which is the time duration of the renewed information collection.

14. Estimate of cost to the Federal government – Provide estimates of annualized cost to the Federal government. Also, provide a description of the method used to estimate costs, which should include quantification of hours, operational expenses such as equipment, overhead, printing, and support staff, and any other expense that would not have been incurred without this collection of information. Agencies also may aggregate cost estimates from items 12, 13, and 14 in a single table:

PHMSA already reviews the incident and annual reports. PHMSA does not expect there will be any additional cost for the Federal government.

15. Explanation of program changes or adjustments – Explain the reasons for any program changes or adjustments reported in items 13 or 14 of the OMB Form 83-I:

Not applicable.

16. Publication of results of data collection – For collections of information whose results will published, outline plans for tabulation, and publication. Address any complex analytical techniques that will be used. Provide the time schedule for the entire project, including beginning and ending dates of the collection of information, completion of report, publication dates, and other actions:

PHMSA will summarize the incident and annual reports post the results on PHMSA’s website.

17. Approval for not explaining the expiration date for OMB approval – If seeking approval to not display the expiration date for OMB approval of the information collection, explain the reasons that display would be inappropriate:

PHMSA will display the expiration date.

18. Exceptions to certification statement – Explain each exception to the certification statement identified in item 19, “Certification for Paperwork Reduction Act Submissions,” of OMB Form 83-I:

There are no exceptions to the certification statement.

Attachments:

1. Forms PHMSA F 7100.1, F 7100.1-1, F 7100.2, and F 7100.2-2 (Forms are part of ICR package – See ROCIS/ICTS document attachments or go to: http://ops.dot.gov/library/forms/forms.htm

2. Authorizing Regulation: 49 CFR 191

ATTACHMENT 2:

Authorizing Regulation: 49 CFR 191

Title 49: Transportation

PART 191—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS

Section Contents

§ 191.1   Scope.
§ 191.3   Definitions.
§ 191.5   Telephonic notice of certain incidents.
§ 191.7   Addressee for written reports.
§ 191.9   Distribution system: Incident report.
§ 191.11   Distribution system: Annual report.
§ 191.13   Distribution systems reporting transmission pipelines; transmission or gathering systems reporting distribution pipelines.
§ 191.15   Transmission and gathering systems: Incident report.
§ 191.17   Transmission and gathering systems: Annual report.
§ 191.19   Report forms.
§ 191.21   OMB control number assigned to information collection.
§ 191.23   Reporting safety-related conditions.
§ 191.25   Filing safety-related condition reports.
§ 191.27   Filing offshore pipeline condition reports.

Authority:   49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, and 60124; and 49 CFR 1.53.

§ 191.1   Scope.

(a) This part prescribes requirements for the reporting of incidents, safety-related conditions, and annual pipeline summary data by operators of gas pipeline facilities located in the United States or Puerto Rico, including pipelines within the limits of the Outer Continental Shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331).

(b) This part does not apply to—

(1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream;

(2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator's facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9.

(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; or

(4) Onshore gathering of gas outside of the following areas:

(i) An area within the limits of any incorporated or unincorporated city, town, or village.

(ii) Any designated residential or commercial area such as a subdivision, business or shopping center, or community development.

[Amdt. 191–5, 49 FR 18960, May 3, 1984, as amended by Amdt. 191–6, 53 FR 24949, July 1, 1988; Amdt. 191–11, 61 FR 27793, June 3, 1996; Amdt. 191–12, 62 FR 61695, Nov. 19, 1997; Amdt. 191–15, 68 FR 46111, Aug. 5, 2003; 70 FR 11139, Mar. 8, 2005]

§ 191.3   Definitions.

As used in this part and the PHMSA Forms referenced in this part—

Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate

Gas means natural gas, flammable gas, or gas which is toxic or corrosive;

Incident means any of the following events:

(1) An event that involves a release of gas from a pipeline or of liquefied natural gas or gas from an LNG facility and

(i) A death, or personal injury necessitating in-patient hospitalization; or

(ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more.

(2) An event that results in an emergency shutdown of an LNG facility.

(3) An event that is significant, in the judgment of the operator, even though it did not meet the criteria of paragraphs (1) or (2).

LNG facility means a liquefied natural gas facility as defined in §193.2007 of part 193 of this chapter;

Master Meter System means a pipeline system for distributing gas within, but not limited to, a definable area, such as a mobile home park, housing project, or apartment complex, where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means, such as by rents;

Municipality means a city, county, or any other political subdivision of a State;

Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters;

Operator means a person who engages in the transportation of gas;

Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof;

Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.

State includes each of the several States, the District of Columbia, and the Commonwealth of Puerto Rico;

Transportation of gas means the gathering, transmission, or distribution of gas by pipeline, or the storage of gas in or affecting interstate or foreign commerce.

[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191–5, 49 FR 18960, May 3, 1984; Amdt. 191–10, 61 FR 18516, Apr. 26, 1996; Amdt. 191–12, 62 FR 61695, Nov. 19, 1997; 68 FR 11749, Mar. 12, 2003; 70 FR 11139, Mar. 8, 2005]

§ 191.5   Telephonic notice of certain incidents.

(a) At the earliest practicable moment following discovery, each operator shall give notice in accordance with paragraph (b) of this section of each incident as defined in §191.3.

(b) Each notice required by paragraph (a) of this section shall be made by telephone to 800–424–8802 (in Washington, DC, 267–2675) and shall include the following information.

(1) Names of operator and person making report and their telephone numbers.

(2) The location of the incident.

(3) The time of the incident.

(4) The number of fatalities and personal injuries, if any.

(5) All other significant facts that are known by the operator that are relevant to the cause of the incident or extent of the damages.

[Amdt. 191–4, 47 FR 32720, July 29, 1982, as amended by Amdt. 191–5, 49 FR 18960, May 3, 1984; Amdt. 191–8, 54 FR 40878, Oct. 4, 1989]

§ 191.7   Addressee for written reports.

Each written report required by this part must be made to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Room 12oo New Jersey AvenueSE., Washington, DC 20590. However, incident and annual reports for intrastate pipeline transportation subject to the jurisdiction of a State agency pursuant to a certification under section 5(a) of the Natural Gas Pipeline Safety Act of 1968 may be submitted in duplicate to that State agency if the regulations of that agency require submission of these reports and provide for further transmittal of one copy within 10 days of receipt for incident reports and not later than March 15 for annual reports to the Information Resources Manager. Safety-related condition reports required by §191.23 for intrastate pipeline transportation must be submitted concurrently to that State agency, and if that agency acts as an agent of the Secretary with respect to interstate transmission facilities, safety-related condition reports for these facilities must be submitted concurrently to that agency.

[Amdt. 191–6, 53 FR 24949, July 1, 1988, as amended by Amdt. 191–16, 69 FR 32892, June 14, 2004; 70 FR 11139, Mar. 8, 2005]

§ 191.9   Distribution system: Incident report.

(a) Except as provided in paragraph (c) of this section, each operator of a distribution pipeline system shall submit Department of Transportation Form RSPA F 7100.1 as soon as practicable but not more than 30 days after detection of an incident required to be reported under §191.5.

(b) When additional relevant information is obtained after the report is submitted under paragraph (a) of this section, the operator shall make supplementary reports as deemed necessary with a clear reference by date and subject to the original report.

(c) The incident report required by this section need not be submitted with respect to master meter systems or LNG facilities.

[Amdt. 191–5, 49 FR 18960, May 3, 1984]

§ 191.11   Distribution system: Annual report.

(a) Except as provided in paragraph (b) of this section, each operator of a distribution pipeline system shall submit an annual report for that system on Department of Transportation Form RSPA F 7100.1–1. This report must be submitted each year, not later than March 15, for the preceding calendar year.

(b) The annual report required by this section need not be submitted with respect to:

(1) Petroleum gas systems which serve fewer than 100 customers from a single source;

(2) Master meter systems; or

(3) LNG facilities.

[Amdt. 191–5, 49 FR 18960, May 3, 1984]

§ 191.13   Distribution systems reporting transmission pipelines; transmission or gathering systems reporting distribution pipelines.

Each operator, primarily engaged in gas distribution, who also operates gas transmission or gathering pipelines shall submit separate reports for these pipelines as required by §§191.15 and 191.17. Each operator, primarily engaged in gas transmission or gathering, who also operates gas distribution pipelines shall submit separate reports for these pipelines as required by §§191.9 and 191.11.

[Amdt. 191–5, 49 FR 18961, May 3, 1984]

§ 191.15   Transmission and gathering systems: Incident report.

(a) Except as provided in paragraph (c) of this section, each operator of a transmission or a gathering pipeline system shall submit Department of Transportation Form RSPA F 7100.2 as soon as practicable but not more than 30 days after detection of an incident required to be reported under §191.5.

(b) Where additional related information is obtained after a report is submitted under paragraph (a) of this section, the operator shall make a supplemental report as soon as practicable with a clear reference by date and subject to the original report.

(c) The incident report required by paragraph (a) of this section need not be submitted with respect to LNG facilities.

[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191–5, 49 FR 18961, May 3, 1984]

§ 191.17   Transmission and gathering systems: Annual report.

(a) Except as provided in paragraph (b) of this section, each operator of a transmission or a gathering pipeline system shall submit an annual report for that system on Department of Transportation Form RSPA 7100.2–1. This report must be submitted each year, not later than March 15, for the preceding calendar year.

(b) The annual report required by paragraph (a) of this section need not be submitted with respect to LNG facilities.

[Amdt. 191–5, 49 FR 18961, May 3, 1984]

§ 191.19   Report forms.

Copies of the prescribed report forms are available without charge upon request from the address given in §191.7. Additional copies in this prescribed format may be reproduced and used if in the same size and kind of paper. In addition, the information required by these forms may be submitted by any other means that is acceptable to the Administrator.

[Amdt. 191–10, 61 FR 18516, Apr. 26, 1996]

§ 191.21   OMB control number assigned to information collection.

This section displays the control number assigned by the Office of Management and Budget (OMB) to the gas pipeline information collection requirements of the Office of Pipeline Safety pursuant to the Paperwork Reduction Act of 1980, Public Law 96–511. It is the intent of this section to comply with the requirements of section 3507(f) of the Paperwork Reduction Act which requires that agencies display a current control number assigned by the Director of OMB for each agency information collection requirement.

OMB Control Number 2137–0522

Section of 49 CFR part 191 where identified	Form No.
191.5	Telephonic.
191.9	RSPA 7100.1
191.11	RSPA 7100.1–1
191.15	RSPA 7100.2
191.17	RSPA 7100.2–1.

[Amdt. 191–5, 49 FR 18961, May 3, 1984, as amended by Amdt.191–13, 63 FR 7723, Feb. 17, 1998]

Part B. Collections of Information Employing Statistical Methods

Not applicable.

1 Small businesses as defined by the Regulatory Flexibility Act (P.L. 96-354)

2 Based on the 2004 U.S. Department of Labor’s Bureau of Labor Statistics National Industry-Specific Occupational Employment and Wage Estimates. The median hourly wage of an engineering manager (for NAICS 486000 – pipeline transportation) is estimated to be $47.96. With an estimated fringe benefit of 35%, the fully loaded cost of an engineering manager in the pipeline industry is $64.75 per hour.

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