41496 Federal Register / Vol. 74, No. 157 / Monday, August 17, 2009 / Notices 

1Reportable 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. 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

[Docket No. PHMSA–2008–0211] 

Information Collection 

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. 

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. 

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. 

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 


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(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 


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41498 Federal Register / Vol. 74, No. 157 / Monday, August 17, 2009 / Notices 

2Question numbers used in this notice refer to 

the numbers on the draft forms about which 

comments were submitted. 

in 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 nonoperator 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-ofway, 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 


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distribution 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. 


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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 


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the 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 subcategories 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 


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individual 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 onecall 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 subcategory 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 presuppose 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 


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the 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 


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additional 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 noticeand-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 


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suggested 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: H2Sll grains/100cf or ll ppm 

and replacing ‘‘[Neither]’’ with ‘‘[Other/ 

Specify:ll].’’ 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-ofway. 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 


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period. 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 


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determining 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-ofcover 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, 


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with 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 subcategory 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 


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needed 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 


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transmission 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 subcategories of Causes associated with 

construction-, fabrication-, installation-, 

and original manufacturing-related 

incidents, while adding a new subcategory for Environmental Crackingrelated 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 subcategories such that PHMSA’s incidents 

can be cleanly mapped to the specific 

threat categories listed in B31.8S. In 

addition, by accommodating this crossmapping 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: 


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• 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 onecall 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 onecall 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 nondestructive 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 vehicleimpact 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 nondestructive evaluations, as such 


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information 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 


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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. 

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 


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also 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 noticeand-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 


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ethanol 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 


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confusion 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 locationdependent, 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. 


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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 postaccident 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 manmade 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 


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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 

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 constructionrelated 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 subcauses 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. 


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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 


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relative 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. 

Issued in Washington, DC on August 10, 

2009. 

Jeffrey D. Wiese, 

Associate Administrator for Pipeline Safety. 

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

BILLING CODE 4910–60–P 


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