72878 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR 191, 192, 193 and 195 

[Docket No. PHMSA–2008–0291; Amdt. Nos. 

191–21; 192–115; 193–23; and 195–95] 

RIN 2137–AE33 

Pipeline Safety: Updates to Pipeline 

and Liquefied Natural Gas Reporting 

Requirements 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), Department of Transportation 

(DOT). 

ACTION: Final rule. 

SUMMARY: This final rule revises the 

Pipeline Safety Regulations to improve 

the reliability and utility of data 

collections from operators of natural gas 

pipelines, hazardous liquid pipelines, 

and liquefied natural gas (LNG) 

facilities. These revisions will enhance 

PHMSA’s ability to understand, 

measure, and assess the performance of 

individual operators and industry as a 

whole; integrate pipeline safety data to 

allow a more thorough, rigorous, and 

comprehensive understanding and 

assessment of risk; and expand and 

simplify existing electronic reporting by 

operators. These revisions will improve 

both the data and the analyses PHMSA 

and others rely on to make critical, 

safety-related decisions, and will 

facilitate both PHMSA’s and states’ 

allocation of pipeline safety program 

inspection and other resources based on 

a more accurate accounting of risk. 

DATES: This final rule is effective 

January 1, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Roger Little by telephone at 202–366– 

4569 or by electronic mail at 

roger.little@dot.gov. 

SUPPLEMENTARY INFORMATION: 

I. Background 

On July 2, 2009, (74 FR 31675) 

PHMSA published a Notice of Proposed 

Rulemaking proposing to revise the 

Pipeline Safety Regulations (49 CFR 

Parts 190–199) to improve the reliability 

and utility of data collections from 

operators of natural gas pipelines, 

hazardous liquid pipelines, and LNG 

facilities. Specifically, PHMSA 

proposed the following amendments to 

the regulations: 

1. Modify 49 CFR 191.1 to reflect the 

changes made to the definition of gas 

gathering lines in Part 192. 

2. Change the definition of an 

‘‘incident’’ in 49 CFR 191.3 to require an 

operator to report an explosion or fire 

not intentionally set by the operator and 

to establish a volumetric basis for 

reporting unexpected or unintentional 

gas loss. 

3. Require operators to report and file 

data electronically whenever possible. 

4. Require operators of LNG facilities 

to submit incident and annual reports. 

5. Create and require participation in 

a National Registry of Pipeline and LNG 

Operators. 

6. Require operators to use a standard 

form in electronically submitting SafetyRelated Condition Reports and Offshore 

Pipeline Condition Reports. 

7. Merge the natural gas transmission 

IM Semi-Annual Performance Measures 

Report with the annual reports. Revise 

the leak cause categories listed in the 

annual report to include those nine 

categories listed in ASME B31.8S. 

Expand information on the natural gas 

transmission annual report to add 

information for miles of gathering lines 

by Type A and Type B gathering, class 

location information by specified 

minimum yield strength (SMYS), 

volume of commodity transported, and 

type of commodity transported. 

8. Modify hazardous liquid operator 

telephonic notification of accidents to 

require operators to have and use a 

procedure to calculate and report a 

reasonable initial estimate of released 

product and to provide an additional 

telephonic report to the NRC if 

significant new information becomes 

available during the emergency 

response phase. 

9. Require operators of hazardous 

liquid pipelines to submit pipeline 

information by state on the annual 

report for hazardous liquid pipelines. 

10. Remove obsolete provisions that 

would conflict with the proposal to 

require electronic submission of all 

reports. 

11. Update Office of Management and 

Budget (OMB) control numbers assigned 

to information collections. 

The statutory authority under 49 

U.S.C. 60101 et seq. authorizes this final 

rule; these Federal Pipeline Safety Laws 

grant broad authority to PHMSA to 

regulate pipeline safety. The proposed 

data collection and filing requirement 

revisions are wholly consistent with 

Section 15 of the PIPES Act of 2006 

(Pub. L. 109–468, December 26, 2006), 

which requires PHMSA to review and 

modify the incident reporting criteria as 

appropriate to ensure that the data 

accurately reflects trends over time. 

For natural gas pipeline operators, 

specific reporting requirements in 49 

CFR Part 191 are found at: 

• § 191.5 Telephonic notice of 

certain incidents. 

• § 191.7 Addresses for written 

reports. 

• § 191.9 Natural gas distribution 

incident report. 

• § 191.11 Natural gas distribution 

annual report. 

• § 191.15 Natural gas transmission 

and gathering incident report. 

• § 191.17 Natural gas transmission 

and gathering annual report. 

• § 191.23 Reporting safety-related 

conditions. 

• § 191.25 Filing safety-related 

condition reports. 

• § 191.27 Filing offshore pipeline 

condition reports. 

The requirement for reporting leaks 

and spills of LNG in accordance with 

Part 191 is found at § 193.2011. Part 191 

has excluded LNG from many of the 

reporting requirements. 

For hazardous liquid pipeline 

operators specific reporting 

requirements in 49 CFR Part 195 are 

found at: 

• § 195.48 Scope. 

• § 195.49 Annual report. 

• § 195.50 Reporting accidents. 

• § 195.52 Telephonic notice of 

certain accidents. 

• § 195.54 Accident reports. 

• § 195.55 Reporting safety-related 

conditions. 

• § 195.56 Filing safety-related 

condition reports. 

• § 195.57 Filing offshore pipeline 

condition reports. 

• § 195.58 Address for written 

reports. 

As the Nation’s repository for pipeline 

data, PHMSA’s data is used not only by 

PHMSA, but by state pipeline safety 

programs, congressional committees, 

metropolitan planners, civic 

associations and other local community 

groups, pipeline research organizations, 

industry safety experts, industry watch 

groups, the media, the public, industry 

trade association, industry consultants, 

and members of the pipeline and energy 

industries. A significant amount of 

critical safety information is cultivated 

from PHMSA’s data through statistical 

analysis and information retrieval. One 

of the agency’s most valued assets is the 

data it collects, maintains, and analyzes 

pertaining to the industry. PHMSA is 

responsible for maintaining the most 

comprehensive collection of accident/ 

incident data for intrastate and 

interstate pipelines in the country. 

PHMSA is subject to continual interest 

and scrutiny by numerous and varied 

stakeholders for the reliability, utility, 

and applicability of information and 

statistics pertaining to pipelines and 

LNG facilities, including the collection, 

tracking, and retrieval of historical data. 

PHMSA, therefore, must periodically 


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modify its information and data 

collections and associated processes to 

address changes in industry business 

practices, changes in PHMSA’s 

regulations, and changes in PHMSA’s 

own data analysis strategies and 

objectives. 

This rule also responds to various 

Government Accountability Office 

(GAO) and National Transportation 

Safety Board (NTSB) recommendations. 

In GAO’s report titled: ‘‘Natural Gas 

Pipeline Safety: IM Benefits Public 

Safety, but Consistency of Performance 

Measure Should Be Improved,’’ (GAO– 

06–946, September, 2006), GAO stated 

that the current gas incident reporting 

requirements do not adjust for the 

changing cost of gas released in 

incidents. GAO recommended that 

PHMSA ‘‘revise the definition of a 

reportable incident to consider changes 

in the price of natural gas.’’ In the same 

report, GAO also recommended PHMSA 

revise reporting of performance 

measures for the IM programs to 

measure the impact of the program. 

GAO recommended that PHMSA 

improve the measures related to 

incidents, leaks, and failures to compare 

performance over time and make the 

measures more consistent with other 

pipeline safety measures. 

The NTSB recommended that PHMSA 

modify 49 CFR 195.52 of the hazardous 

liquid pipeline regulations to require 

pipeline operators to have a procedure 

to calculate and provide a reasonable 

initial estimate of released product in 

their telephonic reports to the NRC 

(NTSB Safety Recommendation P–07– 

07). NTSB also recommended that the 

hazardous liquid regulations require 

pipeline operators to provide an 

additional telephonic report to the NRC 

if significant new information becomes 

available during the emergency 

response (NTSB Safety 

Recommendation P–07–08). This rule 

includes provisions addressing these 

recommendations. 

Section 15 of the PIPES Act of 2006 

(Pub. L. 109–468, December 26, 2006) 

requires PHMSA to review and modify 

the incident reporting criteria to ensure 

that the data accurately reflects trends 

over time. One of the goals of this 

rulemaking is to comply with the 

requirements of this mandate. 

In 2009, PHMSA revised the incident/ 

accident report forms for gas 

transmission, gas distribution and 

hazardous liquid pipelines (August 17, 

2009; 74 FR 41496). The use of these 

new forms were required beginning on 

January 1, 2010. The revisions to these 

forms were intended 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 program. 

II. Analysis of Public Comments 

PHMSA received comments from 37 

organizations including: 

• Eight associations representing 

pipeline operators (trade associations). 

• Fourteen gas distribution pipeline 

operators, many of which also operate 

small amounts of transmission pipeline 

as part of their pipeline systems. 

• Five gas transmission pipeline 

operators. 

• Two LNG facility operators. 

• One operator of both gas 

transmission and hazardous liquid 

pipelines. 

• The National Association of State 

Pipeline Safety Representatives. 

• Two state pipeline regulatory 

authorities. 

• Two pipeline service vendors. 

• One standards developing 

organization. 

• One citizens group. 

Most commenters supported 

PHMSA’s proposal to improve its data 

collection, although many expressed 

concerns over specific aspects of the 

proposal. This section addresses general 

comments regarding PHMSA’s 

approach. We address comments related 

to specific changes proposed in the 

NPRM and on related proposed 

reporting forms individually, below: 

General Comments 

Stability and Consistency 

A number of comments addressed 

stability and consistency in reporting 

and data collection. Southwest Gas 

Corporation (SWGas), Paiute Pipeline 

Company (Paiute), and TransCanada 

noted that PHMSA was revising 

incident report forms not affected by the 

changes proposed in this NPRM 

concurrently but in a separate docket. 

These commenters suggested that the 

dockets be combined or that PHMSA 

delay changes to the incident report 

forms until this proceeding was 

concluded. SWGas and Paiute also 

suggested that all data-collection 

changes should be considered in light of 

their potential impact on other PHMSA 

regulatory initiatives, such as control 

room management and IM for 

distribution pipelines. SWGas and 

Paiute also suggested that cause 

categories (e.g., for leaks, incidents) 

should be consistent across all reports 

and that PHMSA should convene 

working groups to agree on categories 

and the minimal set of data needed. 

They contended that PHMSA’s proposal 

would involve collection of more data 

than it will ever use. Piedmont Natural 

Gas Company (Piedmont) also requested 

that causes be made consistent between 

transmission and distribution, noting 

that it is burdensome to track causes 

differently for each pipeline type. 

Distrigas of Massachusetts LLC 

(DOMAC) suggested that PHMSA and 

the Federal Energy Regulatory 

Commission (FERC) meet to reconcile 

inconsistencies in reporting for facilities 

over which both agencies exercise 

jurisdiction, noting that such a meeting 

was contemplated in the 1993 

Memorandum of Understanding 

between the agencies but has never 

occurred. National Grid requested that 

PHMSA make reporting changes once 

and minimize subsequent changes 

because change is very costly to 

implement and requires an operator to 

modify its management systems for 

collecting data. 

Response 

PHMSA recognizes that changes in 

reporting requirements necessitate a 

change in an operator’s procedures and 

practices and that these changes should 

be infrequent. PHMSA also must change 

its data management systems when 

different data is reported. Yet, good data 

is necessary for PHMSA to understand 

the state of pipeline safety and to 

identify areas where additional 

regulatory attention may be needed. 

PHMSA is updating all of its data 

collection/management and reporting 

requirements so that it has the data that 

it needs to advance as a data-driven 

organization. PHMSA acknowledges 

that the changes made in this final rule, 

and to the incident/accident forms, will 

require the reporting of more data. 

PHMSA is making every effort to assure 

that the outcome of this rulemaking will 

minimize the need for any future 

changes. PHMSA is coordinating all of 

the activities related to data collection 

and does not believe that it is necessary 

to combine dockets. PHMSA is trying to 

establish consistent use of cause 

categories across all types of reporting 

and is considering its data collection 

needs, and the effect of its data 

gathering requirements, in light of its 

other regulatory initiatives. 

PHMSA does not consider that a 

meeting with FERC to reconcile any 

differences in reporting is necessary at 

this time. While FERC and PHMSA 

share jurisdiction over some LNG 

facilities, there are many LNG facilities 

subject to PHMSA’s regulations over 

which FERC exercises no jurisdiction. 


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Implementation 

The AGA, Northeast Gas Association 

(NEGas), Oklahoma Independent 

Petroleum Association (OKIPA) and five 

pipeline operators requested that 

PHMSA allow time for data collection 

processes, databases, and software to be 

modified before new forms are 

implemented. Some suggested allowing 

one year after the effective date of the 

final rule. OKIPA requested 18 months. 

SWGas and Paiute suggested that one 

full calendar year of data collection 

should be allowed before new forms are 

used. TransCanada suggested PHMSA 

conduct a 90-day trial and begin use of 

new forms at the beginning of the 

calendar year following the end of the 

trial, with no retroactive reporting. They 

asserted that this kind of approach is 

needed to make sure the system works 

and that retroactive reporting would be 

unnecessarily redundant and confusing. 

Response 

PHMSA recognizes that it will take 

time for operators to revise their internal 

data management and collection 

systems and processes to report newlyrequired information. At the same time, 

excessive delay only postpones 

PHMSA’s ability to use new data to 

understand better the state of pipeline 

safety. PHMSA does not consider that 

any of the information required in the 

revised forms is new. Pipeline operators 

already collect this information. 

Changes to internal processes may, 

indeed, make it easier to organize and 

report this data, but PHMSA does not 

believe that any retroactive data 

gathering will be required to complete 

the new annual report forms. The 

industry has been aware for some time 

that changes of this nature were in 

development. As discussed above, 

PHMSA needs better data to judge the 

effectiveness of its regulatory activities 

and to make informed decisions about 

future activities. Further postponement 

will only delay PHMSA’s ability to use 

better data. Operators will therefore be 

required to use the new annual report 

forms in 2011 to report data for 2010. 

The information required to complete 

the new LNG incident report form is 

related to the occurrence of an incident 

and is collected during investigation of 

the event, not over time. Thus, the rule 

requires that the new form be used as 

soon as it is approved. However, in 

order to develop its on-line systems, 

PHMSA is delaying the submission of 

the 2010 annual reports for gas 

transmission, LNG and hazardous 

liquids. For the reporting year 2010, the 

gas transmission annual report and the 

LNG annual report will not be required 

to be submitted until June 15th and the 

hazardous liquid annual report will not 

be required to be submitted until August 

15, 2011. In addition, we are delaying 

the implementation of the OPID registry 

requirements until January 1, 2012. 

Additional Comment Opportunity 

The Gas Piping Technology 

Committee (GPTC) and the Pipeline 

Safety Trust (PST) suggested that 

PHMSA allow a second opportunity for 

public comment. They noted that many 

changes were proposed in the NPRM 

and that many issues remain to be 

unresolved. They also noted there are 

significant changes to the related 

reporting forms. 

Response 

PHMSA believes adequate time has 

been given for comment and that an 

additional comment period is not 

needed. PHMSA considers that the 

issues have been well vetted through 

discussions with industry data groups, 

the comments discussed in this notice, 

and discussion at the December 2009 

public meeting of the Technical 

Pipeline Safety Standards Committee 

and the Technical Hazardous Liquid 

Pipeline Safety Standards Committee. 

As discussed below, PHMSA is 

withdrawing the proposed new safetyrelated condition report form. 

Organization of Regulatory Reporting 

Requirements 

AGA, GPTC, DOMAC, and seven 

pipeline operators suggested that 

reporting requirements for gas pipelines 

and LNG facilities should be integrated 

into 49 CFR Parts 192 and 193 

respectively. At present, reporting 

requirements for gas pipelines and LNG 

facilities are consolidated in Part 191 

while the technical safety requirements 

applicable to these facilities are in Parts 

192 and 193. For hazardous liquid 

pipelines, reporting and technical 

requirements are both in Part 195. 

Commenters suggested that relocation of 

the gas/LNG reporting requirements 

would improve clarity. DOMAC 

suggested it would be clearer for LNG 

facility operators given that the 

definitions in Part 193 are more specific 

to LNG—definitions in Part 191 are 

focused more on gas pipelines and can 

create confusion for LNG operators. 

SWGas and Paiute similarly commented 

that they consider LNG facilities to have 

unique characteristics that do not fit a 

pipeline-based reporting scheme. The 

other commenters also suggested that 

future changes would be facilitated and 

questioned why there is a different 

approach in the regulations for gas/LNG 

than for hazardous liquid pipelines. 

Response 

PHMSA did not propose any changes 

in how the pipeline safety reporting 

requirements should be organized. 

Thus, changes to incorporate Part 191 

reporting requirements into Parts 192 

and 193 are beyond the scope of this 

rulemaking. PHMSA will consider if it 

should undertake a future rulemaking to 

make these changes. 

Risk-Based Regulation 

Some commenters questioned 

whether the proposed changes reflect a 

risk-based approach. Technology and 

Management Systems, Inc. (TMS) noted 

that risk-based regulation would require 

consideration of both probability and 

consequences and standards that 

establish criteria on a risk basis. TMS 

also suggested that PHMSA should 

collect time and total volume of product 

flow between incidents, asserting that 

this data is needed for a true 

consideration of risk. DOMAC also 

suggested that throughput data be 

collected from all sectors on annual 

reports to provide a context for analysis 

of safety over time. 

Response 

PHMSA recognizes that a 

determination of risk involves 

consideration of both probability and 

consequence. Many of PHMSA’s recent 

regulatory changes, particularly our IM 

initiatives, have been directed at 

managing risk, and these initiatives 

involve consideration of both the 

probability of an adverse event 

occurring and its potential 

consequences. PHMSA also recognizes 

that true ‘‘risk-based’’ regulation would 

involve standards expressed in terms of 

numerical thresholds related to risk. 

PHMSA does not consider such an 

approach practical for regulation of 

pipeline safety at this time. 

PHMSA does not agree that collecting 

information on time and volume of 

product flow between incidents would 

serve PHMSA’s needs or provide a 

better analysis of risk. Similarly, 

additional data concerning product 

throughput is not needed. Overall 

information on product movement is 

available from data PHMSA and the 

Energy Information Administration 

collect on annual reports, and this 

information can be used to understand 

the context in which pipeline incidents 

occur. 

Definitions and Terminology 

Some commenters requested that 

PHMSA add definitions for terms not 

now formally defined in the regulations. 

PST suggested adding definitions to Part 

191 for gas pipeline facility/facilities, 


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LNG plant, production facility, 

distribution pipeline system, gathering 

pipelines, and transmission pipelines, 

noting that these terms are used in the 

part but not now defined. DOMAC 

requested that the regulations refer to an 

‘‘LNG facility’’ rather than an ‘‘LNG plant 

or facility,’’ because the regulations only 

define the term facility. El Paso Pipeline 

Group (El Paso) suggested that terms be 

defined as needed, particularly the term 

‘‘explosion.’’ SWGas and Paiute 

recommended clarifying use of the term 

‘‘significant,’’ noting that the regulatory 

analysis supporting the NPRM used this 

term to describe events using the same 

criteria as those defining accidents in 

§ 195.50. El Paso suggested that the 

references to ‘‘subchapter’’ in proposed 

§ 192.945 be revised to refer to ‘‘part’’ as 

found elsewhere in the regulations. 

Response 

In the NPRM, PHMSA did not 

propose to add the definitions suggested 

by PST to Part 191. PHMSA cannot now 

add definitions in the final rule without 

having allowed an opportunity for 

public comment. PHMSA notes that 

many of the terms are defined in Parts 

192 and 193 and are thus commonly 

understood within the pipeline 

industry. PHMSA does not consider the 

lack of these definitions in Part 191 to 

be a cause of confusion. PHMSA will 

consider if future rulemaking is needed 

to define additional terms in Part 191. 

PHMSA does not consider that all 

terms used in the pipeline safety 

regulations must be defined explicitly. 

Terms require definition when they 

have particular meanings within the 

regulations. Terms that are used that 

reflect their commonly understood 

meaning need not be defined explicitly. 

As such, PHMSA does not think it is 

necessary to define ‘‘LNG plant’’ or to 

refer only to an ‘‘LNG facility’’ because 

that term is defined in Part 193. The use 

of ‘‘plant’’ to describe an industrial 

facility is common within the English 

language and does not need an explicit 

definition. 

PHMSA also does not find it 

necessary to define the term 

‘‘explosion.’’ Although there are 

accepted technical definitions for this 

term, many involve factors, such as 

consideration of the magnitude of the 

resulting pressure wave that would 

require data not normally available for 

a pipeline event. At the same time, 

PHMSA considers that the difference 

between ‘‘ignites’’ (or burns) and 

‘‘explodes’’ is commonly understood, 

and that reliance on this common 

understanding results in less confusion 

than would result from trying to apply 

a formal definition. 

With respect to the term ‘‘significant,’’ 

that term was used in the regulatory 

analysis to differentiate events that 

require reporting as accidents from 

events of lesser importance. It was not 

intended to reflect any more-important 

subset of reported incidents/accidents. 

Regulatory evaluations are prepared to 

explain the basis and benefits of 

proposed regulatory changes to all 

stakeholders, including those not 

directly involved in the regulated 

industry. It is thus necessary to reflect 

that not all adverse events that occur at 

a pipeline facility are reported as 

incidents, only those that are 

significant. 

Proposed § 192.945 included two 

references to other sections of the 

pipeline safety regulations, one of 

which is in another Part (Part 191). 

Therefore, we must use ‘‘of this 

subchapter’’ for that reference. The other 

reference to § 192.7 should be referred 

to as ‘‘of this part.’’ PHMSA has revised 

this section accordingly. 

Miscellaneous 

PST opposes the use of the National 

Pipeline Mapping System (NPMS) to 

collect data if information will not be 

available to the public via that system. 

El Paso and Spectra Energy 

Transmission LLC (Spectra) requested 

that PHMSA encourage all stakeholders 

to make use of the reported data. They 

noted that they currently answer many 

telephone calls from PHMSA and state 

pipeline safety regulatory personnel 

seeking information that this proposed 

rule would require be reported. 

OKIPA requested that PHMSA 

provide examples of significant 

information that would require a 

supplemental incident report under 

§ 191.15(c). 

Response 

PHMSA does not intend to use NPMS 

to gather data proposed for the annual 

reports. As we noted, PHMSA is 

redesigning its own information 

management systems. These changes 

will make information more readily 

available to PHMSA and state regulatory 

personnel. PHMSA will encourage its 

staff to obtain information from the 

PHMSA systems rather than 

telephoning operators. 

Section 191.15(c) does not require a 

supplemental report for ‘‘significant’’ 

information, and thus no examples are 

necessary to illustrate significance. This 

paragraph requires a supplemental 

incident report when additional 

information becomes known after an 

initial incident report is submitted. This 

could include information necessary to 

complete a section of the incident report 

form that was left blank in the initial 

submission because the information was 

not yet known. It could also include 

additional information that the operator 

concludes is important to understanding 

the incident and which the operator 

would report in the narrative section of 

the form. 

III. Discussion of Public Comments on 

Individual Issues 

(1) Modifying the Scope of Part 191 To 

Reflect the Change to the Definition of 

Gas Gathering Lines 

49 CFR 191.1 

Proposal 

In the NPRM, PHMSA proposed to 

revise the scope of Part 191 to address 

an inadvertent omission in the March 

15, 2006, final rule that redefined the 

definition of gas gathering pipelines in 

Part 192. Part of that rulemaking effort 

revised § 192.1 to reflect the change in 

the scope of Part 192. A corresponding 

change was not made to the scope of 

Part 191, which specifies requirements 

for reporting incidents and other events 

and for submission of annual reports by 

operators of pipelines subject to Part 

192. Because of this omission, there was 

confusion whether operators of 

gathering lines that became regulated 

only with the 2006 rule were required 

to submit reports. Further, operators of 

gathering lines have been reporting the 

number of miles of gas gathering lines 

by the old definition and not by the new 

definition in Part 192. 

Comments 

The Texas Oil and Gas Association 

(TXOGA) and Atmos Energy 

Corporation (Atmos) suggested 

clarifying § 191.15, requiring 

submission of incident reports, and 

§ 191.17, requiring annual reports, to 

indicate that they apply only to 

regulated gathering lines. 

The National Association of Pipeline 

Safety Representatives, supported by the 

Iowa Utilities Board (IUB), suggested 

PHMSA require operators of all 

gathering lines to report incidents, 

regardless of whether they are regulated 

under Part 192. The commenters noted 

that data on incidents that occur on 

non-regulated lines is necessary to 

determine whether additional regulation 

is needed. 

Response 

PHMSA has not changed the 

proposed regulatory language. Section 

191.1(b)(4)(ii), as revised in this final 

rule, clearly states that Part 191 does not 

apply to gathering lines that are not 

regulated gathering lines as determined 

in accordance with § 192.8. Thus, none 


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1The criterion for reporting property damage 

exceeding $50,000 was established in 1984 and 

began widespread use in 1985. 

of the provisions in Part 191, including 

§§ 191.15 and 191.17, applies to nonregulated gathering lines. The 

clarification TXOGA and Atmos 

requested is not needed. 

PHMSA agrees that data for incidents 

that occur on non-regulated gathering 

lines could be useful in determining 

whether these pipelines should be 

brought under the reporting regulations. 

However, PHMSA did not propose such 

a change. PHMSA would have to 

undertake a new rulemaking to bring 

unregulated gathering lines under Part 

191 incident reporting requirements. 

(2) Changing the Definition of an 

‘‘Incident’’ for Gas Pipelines 

49 CFR 191.3 

Proposal 

In the NPRM, PHMSA proposed to 

change the definition of an incident in 

49 CFR 191.3 to establish a new 

reporting category: An explosion or fire 

not intentionally set by the operator. 

This proposed change would make the 

definition consistent with the accident 

reporting criteria for hazardous liquid 

pipelines in Part 195. 

The NPRM also proposed to establish 

a volumetric basis of 3,000 Mcf (the 

abbreviation ‘‘Mcf’’ means thousand 

cubic feet) for reporting unintentional 

gas loss. This proposal responded to a 

GAO recommendation. In a report titled: 

‘‘Natural Gas Pipeline Safety: Integrity 

Management Benefits Public Safety, but 

Consistency of Performance Measure 

Should Be Improved,’’ (GAO–06–946, 

September, 2006), GAO stated that the 

current gas incident reporting 

requirements do not adjust for the 

changing cost of gas released in 

incidents. GAO recommended that 

PHMSA ‘‘revise the definition of a 

reportable incident to consider changes 

in the price of natural gas.’’ 

In November 2005, the Interstate 

Natural Gas Association of America 

(INGAA) submitted a petition for 

rulemaking recommending PHMSA 

adopt a volume basis instead of the cost 

of gas lost. INGAA recommended 20 

million standard cubic feet as a 

reporting threshold. INGAA based this 

volume on the $50,000 reporting 

threshold and the 1985 1 cost of gas at 

$2.50 per Mcf. 

The proposed change responded to 

both the GAO recommendation and the 

INGAA petition. It would remove the 

cost of gas lost from consideration in 

determining whether an event 

constitutes an incident under the 

existing criterion of $50,000 damage. 

This would correct the problem GAO 

identified in that the volatility of gas 

prices would no longer be an issue in 

determining whether a particular event 

met the definition of an incident. The 

new criterion would separately capture 

events in which a large quantity of gas 

is lost regardless of the value of 

resulting property damage. 

The proposal also changed the 

language preceding the criteria to make 

clear that an incident was an event that 

resulted in one of the listed 

consequences. Previously, the 

regulations referred only to events that 

‘‘involve[d]’’ one of the consequences 

and it was not clear that events of 

interest were those in which the gas 

pipeline failure resulted in the listed 

consequences. 

Comments 

Causality 

INGAA, the Texas Pipeline 

Association (TPA), TransCanada, and 

NiSource Gas Transmission and Storage 

(NiSource) supported the change to 

make it clear that events only become 

incidents if the listed consequences 

resulted from a release of gas from a 

pipeline. DOMAC and National Grid 

disagreed, noting that conclusions of 

causality could imply legal liability, and 

expressing a preference for the former 

structure of reporting events that 

‘‘involve’’ stated consequences to avoid 

pre-judging liability. 

Explosion or Fire Not Intentionally Set 

by the Operator 

AGA, the American Public Gas 

Association (APGA), GPTC, NAPSR, 

IUB, and many pipeline operators 

objected to the addition of this criterion. 

Many of these comments reflected 

confusion about fires that did not result 

from the gas pipeline failure. 

Commenters noted, for example, that 

over 400,000 structure fires occur each 

year in the U.S. In many of those fires, 

a gas meter is damaged and gas 

subsequently becomes involved in the 

pre-existing fire. These commenters 

maintained that PHMSA has no 

jurisdiction over fires that begin from 

non-pipeline causes and that reporting 

these events as pipeline incidents 

would significantly misrepresent 

pipeline safety and would distort 

current incident trends. They also 

asserted that other agencies (e.g., 

Federal Emergency Management 

Agency) already collect fire data. 

GPTC and several operators 

commented that a brief ‘‘fire’’ is an 

expected operational event during many 

activities associated with operation and 

maintenance of gas distribution 

pipelines. DOMAC claimed, for 

example, that the proposed criterion 

would require reporting of a lightning 

strike that ignites a gas relief vent that 

is designed to close and snuff out the 

resulting fire with no safety 

consequences. APGA argued that this 

criterion could significantly increase the 

number of ‘‘incidents’’ and that PHMSA 

had not considered the significant 

burden that could result due to existing 

requirements to test personnel involved 

in an incident for drugs and alcohol. 

Some commenters also objected that 

analyses referred to in the NPRM in 

support of this proposed new criterion 

were not included in the docket for 

public examination. Several pipeline 

operators suggested that the new 

criterion was not needed since the 

remaining criteria would provide a 

complete picture of consequential 

events. 

INGAA, El Paso, and Spectra took a 

contrary position and suggested that the 

proposed new criterion apply to events 

resulting from intentional and 

unintentional releases of gas. 

IUB suggested that we should not 

exclude fires intentionally set by an 

operator because hazardous liquid 

pipeline operators sometimes 

intentionally set fires to consume 

released product that cannot otherwise 

be recovered. 

AGA commented that nearby fires 

should be deleted as a primary cause of 

a gas pipeline incident because these are 

outside PHMSA jurisdiction. 

Volume Measure for Released Gas 

AGA, NAPSR, IUB, and several 

pipeline operators questioned the 

practicality of the proposed criterion. 

AGA and several pipeline operators 

noted the difficulty in calculating the 

amount of a release within two hours, 

by which time a telephonic report of an 

incident is expected. They contended 

that factors necessary for this analysis 

are not readily obvious. IUB, Atmos, 

and Michigan Consolidated Gas 

(MichCon) questioned the applicability 

of this criterion to distribution pipeline 

incidents. They noted that property 

damage is the predominant component 

of costs for distribution incidents, and 

that the concern expressed by INGAA 

and others that increases in the cost of 

gas (and resulting increase in the 

calculated cost of gas lost) strongly 

influence the determination of whether 

an event constitutes an incident 

generally is not applicable to 

distribution pipeline events. They also 

noted that it is sometimes difficult to 

calculate the amount of gas lost in 

distribution events. SWGas and Paiute, 


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distribution and transmission pipeline 

operators respectively, agreed, stating 

that the volume of gas lost was usually 

ancillary to other reporting criteria. 

Baltimore Gas & Electric (BG&E) 

suggested eliminating or qualifying this 

criterion to apply only to unintended 

releases. BG&E contended that release of 

gas is a routine part of doing business 

and classifying such events as incidents 

could distort safety trends. 

Most commenters questioned the size 

of the proposed criterion. Many noted 

that it was incorrectly stated in the 

proposed rule language as 3,000 million 

cubic feet, although the preamble 

discussion described the proposed 

amount as 3,000 Mcf. The industry trade 

associations and many operators argued 

that the proposed magnitude of the 

criterion is too small and that 3,000 Mcf 

is inconsistent with a criterion of 

$50,000 in property damage. INGAA 

suggested that the release criterion 

should be 20,000 Mcf. Other 

commenters suggested different values, 

varying between 10,000 and 20,000 Mcf. 

Northern Natural Gas (Northern) and 

Spectra (gas transmission pipeline 

operators) suggested that it would be 

appropriate to establish different criteria 

for gas transmission and distribution 

pipelines. 

INGAA and several pipeline operators 

requested clarification concerning how 

the proposed criterion was to be 

applied. El Paso and Spectra contended 

that intentional releases, including from 

appurtenances designed to release gas 

(e.g., relief valves) should not require 

reporting because these are not 

consequential incidents. These 

operators also suggested that the 

criterion not be applied to small leaks 

that might release large quantities of gas 

over an extended period. Similarly, 

NiSource commented that the criterion 

should only apply to immediate releases 

resulting from an event and should 

exclude subsequent blowdowns which 

have no significant effect on public 

safety. INGAA, El Paso, and 

TransCanada also suggested that the 

criterion be limited to gas lost at the 

incident location because gas lost at 

controlled locations (such as would be 

used for blowdowns) does not pose the 

same risk. 

The industry trade associations and 

several operators also requested that 

PHMSA make clear that the 

introduction of this new criterion means 

that the cost of gas lost will no longer 

be used in determining whether an 

event constitutes an incident because of 

$50,000 in property damage costs. PST 

also requested clarification in this area. 

IUB suggested that PHMSA should 

provide guidance on how the amount of 

gas lost is to be calculated. 

Property Damage Criterion 

AGA and a number of pipeline 

operators commented that the existing 

criterion of $50,000 property damage is 

too low and should be raised. The 

commenters noted that this criterion 

was established in 1984 and has not 

been adjusted since; inflation has made 

events reportable that would not have 

been reportable in 1984. Commenters 

suggested that the criterion should be 

increased to $100,000, that it should be 

revised periodically or indexed for 

inflation, or that various categories of 

costs should be excluded from 

consideration. Contrary to this general 

trend, SWGas and Paiute suggested that 

all costs, including third-party damages 

and costs to relight customers, should 

be included, since these are costs 

directly related to the event. 

Miscellaneous 

PHMSA received several comments 

related to the definition of a gas pipeline 

incident that did not fit into the 

categories discussed above. 

MidAmerican, a gas distribution 

pipeline operator, suggested not to 

change the definition because the 

proposed changes would add events of 

little or no safety significance and divert 

resources from safety. The Missouri 

Public Service Commission (MOPSC) 

suggested revising the existing criterion 

related to injuries to include medical 

care at an emergency room or other 

facility in addition to inpatient 

hospitalization. MOPSC contended that 

changes in the practice of medicine 

have resulted in many injuries that 

formerly required inpatient 

hospitalization now being treated at 

such facilities. INGAA, NAPSR, 

Northern, Atmos, and TransCanada 

commented that incidents should be 

limited to unintentional releases of gas). 

MOPSC suggested that the definition 

not be limited to releases ‘‘from a 

pipeline,’’ given that consequential 

events can result from releases at other 

locations (e.g., fuel lines). AGA and 

BG&E noted that it is impractical to 

make incident criteria the same for 

hazardous liquids and natural gas 

because there are fundamental 

differences between hazardous liquid 

and gas pipelines, particularly gas 

distribution pipelines. 

Response 

Causality 

PHMSA is sensitive to the potential 

legal issue raised by DOMAC and 

National Grid. PHMSA understands that 

an initial conclusion that a pipeline 

event ‘‘resulted in’’ certain consequences 

may differ from a legal finding that the 

pipeline event caused those 

consequences, resulting in liability. 

Still, PHMSA concludes that it is 

important to consider causality in 

reporting incidents. 

PHMSA’s mission is to protect public 

health and safety and the environment 

from risks associated with transporting 

hazardous materials by pipeline. 

PHMSA’s concern in requiring the 

reporting of incidents is that it 

understands fully the extent to which 

problems on regulated pipelines result 

in adverse impacts on safety and the 

environment. Accordingly, PHMSA’s 

analyses of its incident data always 

assume a degree of causality between 

the pipeline failure and the reported 

consequences. It is therefore important 

that this data be collected so that it is 

limited to those events in which a 

pipeline failure resulted in adverse 

consequences, rather than instances in 

which the event happened to occur 

concurrently with circumstances that 

meet one of the criteria defining an 

incident (i.e., death, injury, or property 

damage exceeding the reporting 

threshold). PHMSA is thus persuaded 

that the incident definition in § 191.3 

should require a conclusion of a degree 

of causality (which does not imply legal 

liability). 

Causality has been treated in the 

§ 195.50 requirement for accident 

reports for hazardous liquid pipelines 

for many years. Hazardous liquid 

operators have not complained to 

PHMSA that this treatment has 

adversely affected them in any liability 

proceedings. PHMSA has accepted the 

suggestion to conform the treatment of 

incidents in Part 191 to that of accidents 

in Part 195; therefore, this final rule 

defines a gas pipeline incident as ‘‘a 

release of gas from a pipeline, or of 

LNG, liquefied petroleum gas, 

refrigerant gas, or gas from an LNG 

facility, and that results in one or more 

of the following consequences:’’. 

Explosion or Fire Not Intentionally Set 

by the Operator 

PHMSA has not included in this final 

rule the proposed new criterion 

concerning fires or explosions not 

intentionally set by the operator. 

PHMSA is persuaded by the comments 

that it did not adequately consider the 

effect of this new criterion and the 

resulting burden. In addition, as 

discussed above, PHMSA has revised 

the definition of an incident in § 191.3 

to include an implied causal 

relationship between a pipeline failure 

and one of the listed consequential 


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events. PHMSA concludes that these 

changes will eliminate the perceived 

need to report the vast majority of 

events in which a fire existed before the 

gas pipeline failure (so-called ‘‘fire first’’ 

events). 

At the same time, PHMSA does not 

agree that no ‘‘fire first’’ events should be 

considered. PHMSA considers the 

argument that it lacks jurisdiction over 

fires not resulting from pipeline failures 

to be irrelevant. PHMSA also lacks 

jurisdiction over excavation near 

pipelines or over severe weather events 

(e.g., hurricanes), both of which often 

result in pipeline incidents. PHMSA has 

a responsibility to assure that the 

pipeline facilities over which it has 

jurisdiction are adequately protected 

from events, including excavation, 

hurricanes, and nearby fires, that could 

cause safety-significant problems in 

those facilities regardless of whether it 

has jurisdiction over the events 

themselves. PHMSA collects incident 

data, in large part, to assure that this 

protection is adequate or to identify 

instances in which additional regulation 

is required to assure adequate 

protection. 

As part of a separate proceeding 

involving changes to incident/accident 

reporting forms, PHMSA has revised the 

form’s instructions to clarify that 

secondary ignition events—those events 

where the fire exists first and 

subsequently results in damage to 

pipeline facilities—need only be 

reported if the damage to pipeline 

facilities exceeds $50,000 (one of the 

incident-defining criteria in this rule). 

This provision was included in incident 

reporting instructions prior to a form 

change in 2004. A NAPSR resolution, 

included as an attachment to its 

comments filed in this docket, sought 

restitution of this provision as its 

proposed solution to the problem posed 

by ‘‘fire first’’ events. PHMSA agrees. 

The changes in this final rule and to the 

reporting instructions should eliminate 

the need to report the vast majority of 

structure fires, since few structures are 

associated with pipeline facilities that 

could result in $50,000 damage (the 

value of a typical residential meter set 

is a few hundred dollars). The changes 

will result in reporting of significant 

pipeline failures caused by nearby fires 

(e.g., forest fires), which are appropriate 

for PHMSA’s consideration in the same 

manner as other events that cause 

pipeline incidents. 

Volume Measure for Released Gas 

PHMSA concludes that many of the 

comments regarding this criterion 

resulted from the relatively low volume 

proposed. This led to concerns about 

the need to report routine releases 

associated with operational events, such 

as leaks and blowdowns. PHMSA 

analyzed incident reporting from 2004 

through 2009 to assess the impacts that 

a 3,000 Mcf vs. a 10,000 Mcf volumetric 

reporting threshold would have on 

incident reporting frequency. Both gas 

transmission and gas distribution 

incident reporting during that timeframe 

included the cost of gas lost, facilitating 

the comparison. The comparison 

indicates that at 10,000 Mcf, we would 

lose about 20 incident reports per year 

across both gas transmission and gas 

distribution incident reporting. Because 

the annual frequency is very low (about 

135 gas transmission and about 150 gas 

distribution incidents annually), 

PHMSA believes that lowering the 

numbers further would adversely 

impact our ability to effectively conduct 

safety analysis and trending. Our 

analysis shows that at the 3,000 Mcf 

threshold, we estimate we would lose 

six incident reports per year. INGAA 

had suggested a threshold of 20,000 

Mcf, an amount that corresponds to the 

amount of gas that would have cost 

$50,000 when the property damage 

threshold was revised in 1984. PHMSA 

agrees that relating the volume 

threshold to the property damage 

threshold is appropriate, but does not 

agree that this should be done on the 

basis of 1984 costs. Incidents are 

reported based on current costs. Absent 

this rule change, an event that resulted 

in loss of approximately 10,000 Mcf 

would be reportable as a loss of $50,000 

of gas (considering current costs). 

However, as PHMSA concludes from a 

comparison of 10,000 Mcf to 3,000 Mcf 

as stated above, the impact of lowering 

the already low frequency of reporting 

further would impact safety trending 

capability, therefore, we have chosen to 

maintain the proposed 3,000 Mcf 

threshold for the volume release 

criterion. This final rule requires 

reporting of releases that meet or exceed 

‘‘3 million cubic feet’’ (i.e., 3,000 Mcf). 

PHMSA recognizes that initial 

calculations are approximate, but does 

not consider this a reason not to report 

events that have consequence. 

PHMSA recognizes that the amount of 

gas lost in distribution incidents is 

usually less than that for transmission 

pipelines. This means that there will 

likely be fewer events that are defined 

as incidents on distribution pipelines 

due to the volume of gas released if the 

same criterion is used for both types of 

pipelines. Nevertheless, PHMSA 

considers use of a common criterion 

appropriate. Distribution events more 

often become ‘‘incidents’’ due to the 

amount of property damage that occurs 

or as a result of death or injury. This 

reflects real differences between 

transmission and distribution pipelines. 

Using a different volume release 

criterion for distribution pipelines to 

force the number of reported incidents 

to be similar to that of transmission 

pipelines would distort analytical 

results and obscure these real 

differences. 

PHMSA agrees that intentional, 

controlled releases are not events with 

significant safety consequences. PHMSA 

has revised the final rule to clarify that 

reporting under the volume threshold is 

only required for ‘‘unintended’’ releases 

that exceed the specified amount. Yet, 

PHMSA does not agree that other 

criteria should be limited to 

unintentional releases. PHMSA 

considers that an intentional release that 

results in death, inpatient 

hospitalization, or $50,000 in property 

damage would be an event with 

significant safety consequences and 

should be reported as an incident. 

The intent of this new criterion is to 

separate lost gas from other property 

damage costs to preclude the volatility 

of gas prices from affecting which 

events are defined as incidents. PHMSA 

has revised the final rule to make clear 

that the cost of gas lost is not to be 

included in the calculation of property 

damages for comparison with the 

$50,000 criterion. 

Property Damage Criterion 

The NPRM did not include any 

change to the existing $50,000 property 

damage criterion. As such, changes to 

this criterion would be outside the 

scope of this rulemaking. However, 

PHMSA does believe that because the 

annual frequency of both gas 

distribution and gas transmission 

incident reporting is extremely low as 

noted above, a reevaluation of that 

threshold is appropriate and PHMSA 

may take that under consideration in the 

future. 

Miscellaneous 

PHMSA does not agree that the 

changes in the definition of a gas 

pipeline incident add events of little 

safety significance. As discussed above, 

these events are significant. PHMSA has 

made clarifications to eliminate 

reporting of non-consequential events 

(e.g., intentional blowdowns and most 

‘‘fire first’’ events). PHMSA does not 

consider that these changes will result 

in any inappropriate redirection of 

resources. 

Similarly, PHMSA did not propose 

any change to the existing criterion for 

injury; therefore, MOPSC’s suggested 


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changes to this criterion would be 

outside the scope of this proceeding. 

PHMSA notes, however, that inpatient 

hospitalization is an objective criterion. 

Other treatment can vary based on local 

practices. In some areas, people with 

minor injuries may still be taken to 

emergency rooms as a precautionary 

measure, but those patients would not 

be admitted unless their injuries were 

serious. PHMSA considers the existing 

criterion appropriate. 

PHMSA has discussed above its 

reasons for requiring reporting of events 

resulting from intentional releases of 

gas, excluding events that result solely 

in loss of gas, as incidents. Pipelines 

and pipeline facilities are PHMSA’s 

focus of regulatory concern; therefore, 

PHMSA has not accepted MOPSC’s 

suggestion to expand the scope of 

incidents beyond releases from these 

facilities. 

PHMSA agrees that the criteria 

defining an incident for hazardous 

liquid and gas pipelines should 

recognize differences between those 

pipelines and the commodities they 

carry. As discussed above, PHMSA has 

decided not to include a criterion in the 

definition of a gas pipeline incident 

related to a fire not intentionally set by 

the operator or an explosion. Such a 

criterion has long been part of the 

definition of an accident for a hazardous 

liquid pipeline. 

(3) Requiring Electronic Reporting and 

Filing of Reports 

49 CFR 191.7 and 195.58 

Proposal 

In the NPRM, PHMSA proposed to 

require operators of a regulated pipeline 

or facility to submit all reports to 

PHMSA electronically. This proposal 

was intended to improve the processing 

of submitted reports and reduce 

paperwork burdens. 

Comments 

Most commenters supported 

electronic reporting, while APGA 

suggested retaining an option for paper 

filing for very small distribution 

operators that may lack internet access. 

GPTC noted that the proposed 

requirement to apply for non-electronic 

submission 60 days in advance of a 

report being due was inconsistent with 

the requirement to submit incident 

reports in 30 days. OKIPA requested 

that PHMSA describe the criteria it will 

use to review applications for nonelectronic reporting and to assure 

consistency among states. PST objected 

to allowing an option for non-electronic 

reporting, noting that internet access is 

now widely available. 

Many commenters addressed the 

process by which electronic reports will 

be made. The American Petroleum 

Institute (API) and the American 

Association of Oil Pipelines (AOPL) 

argued that electronic reporting should 

be more than completing a form on the 

computer; it should include internal 

checks to prevent incorrect entries, 

assure data consistency, etc. API and 

AOPL also suggested that a narrative 

description should continue to be part 

of incident reports. API, AOPL, AGA, 

GPTC, and several pipeline operators 

suggested that the on-line system allow 

for saving interim work and printing a 

completed form before submission. API, 

AOPL and Atmos proposed that the 

system allow for electronic submission 

of a completed template to save time 

and reduce potential for errors. Pipeline 

operators recommended that the on-line 

system allow users to print a blank 

form, provide electronic confirmation of 

submission, and provide clear guidance 

for updating/modifying/superseding 

reports in the event of new information. 

National Grid commented that controls 

should be established to allow 

submissions only by a company’s 

designated representative. APGA, GPTC, 

and Northern Illinois Gas Company 

(Nicor) maintained that reports should 

not be considered late-filed if the online system is not available on the date 

on which a report submission is 

required. 

Northern suggested that the on-line 

system should also allow a report to be 

rescinded electronically, which would 

be consistent with requiring electronic 

submissions and would be less 

burdensome. Piedmont advised that 

PHMSA should staff sufficiently to 

handle data correction requests based 

on their experience that it is difficult to 

correct data once submitted. 

APGA, GPTC, and NiSource suggested 

revising the regulations to allow 

electronic submittal of reports that must 

be made immediately to the NRC, noting 

that the NRC system now provides for 

this alternate method. 

API, AOPL, TPA, TXOGA, and Atmos 

commented that separate reports should 

not be required for interstate agents and 

states; instead current technology allows 

reports to be forwarded to the 

appropriate agency based on the 

location of assets involved. 

Response 

PHMSA agrees that a paper-filing 

option must be provided, although 

PHMSA expects that the need for 

alternate submission will be rare. At the 

same time, PHMSA is persuaded that its 

proposed option to apply for nonelectronic filing was unduly 

burdensome. A requirement to request 

non-electronic reporting 60 days in 

advance is, as commenters noted, 

inconsistent with a requirement to 

report incidents in 30 days. In addition, 

requiring a request for non-electronic 

filing separately for each report 

unnecessarily adds burden for operators 

and PHMSA because the same few 

operators are likely to apply for 

approval repeatedly. PHMSA has 

revised the final rule to eliminate the 

requirement to request an alternate 

reporting method 60 days in advance of 

each required submission. The final rule 

provides that operators may apply for 

use of alternate submission methods 

and that approvals of such requests may 

be indefinite or until a date specified by 

PHMSA, eliminating the need to apply 

separately for each required submission. 

PHMSA will review the description of 

the undue burden that would be 

imposed by a requirement to file 

electronically but does not find it 

necessary or appropriate to define 

specific criteria for acceptance or denial 

at this time. The requirement for 

electronic submission, and for alternate 

methods, applies to submissions made 

to PHMSA; therefore, the question of 

consistency among states is not at issue 

here. 

PHMSA’s electronic reporting system 

includes the options commenters 

requested. This system is already being 

used for recently revised incident/ 

accident report forms. The system 

includes internal checks for data 

consistency and incorrect entries (e.g., 

entering text in a numeric field). It 

allows saving of work in progress and 

printing of completed or blank forms. 

Where forms are printed before 

submission, the word ‘‘DRAFT’’ appears 

as a diagonal watermark to avoid later 

confusion as to whether a filed copy 

represents information that was actually 

submitted. The incident reports provide 

for a narrative description. Confirmation 

of submission is provided by an 

electronic date stamp visible to both the 

submitting operator and PHMSA. 

PHMSA has not allowed for 

submission of a completed template in 

lieu of entering the information on-line. 

On-line data entry provides for data 

quality checks that would not be 

possible with uploaded files. These 

controls are important to help reduce 

the need for data correction, and are 

expected to help address the difficulties 

with data correction raised by 

Piedmont. 

Submissions are made using user 

identification and passwords that are 

provided to a company’s designated 

person. PHMSA does not consider it 

necessary to modify further its on-line 


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system to allow submission only by 

designated company representatives. 

Operators should control dissemination 

of their ID/password as they would for 

any password-protected computer 

system. 

PHMSA has not adopted Northern’s 

suggestion to allow reports to be 

rescinded electronically. Although this 

may be easier, rescissions need to be 

made through PHMSA’s staff for data 

quality reasons. 

PHMSA has eliminated requirements 

to file duplicate copies of reports with 

states with the exception of safetyrelated condition reports. PHMSA is 

required by statute (49 U.S.C. 60102(h)) 

to provide for concurrent notice of 

safety related conditions to appropriate 

State authorities. 

As suggested by commenters, PHMSA 

has revised §§ 191.5 and 195.52 to allow 

operators the option of submitting online reports of certain incidents to the 

NRC (NRC). The NRC now allows for 

electronic reporting of incidents; 

therefore, including this option in 

PHMSA’s regulations imposes no new 

burden on the regulated industry. 

(4) Requiring LNG Operators To Submit 

Incident and Annual Reports 

49 CFR 191.9, 191.15, 191.17 and 

193.2011 

Proposal 

In the NPRM, PHMSA proposed to 

amend §§ 191.9, 191.15, 191.17, and 

193.2011 to require LNG facility 

operators to submit annual and incident 

reports consistent with the current 

reporting requirements for gas and 

hazardous liquid pipeline operators. 

LNG facility operators had previously 

been exempted from these requirements. 

Comments 

SWGas and Paiute contended that 

submission of incident reports for LNG 

facilities is not needed because 

incidents at these facilities are very rare. 

BG&E and MidAmerican also 

maintained that annual reports are 

unnecessary because these facilities are 

static and the reported information will 

not change from year to year. SWGas 

and Paiute claimed that the need for 

annual reports to justify user fees is 

specious given that fees are currently 

determined by tank volume. These 

operators also contended that it was not 

possible to estimate the burden for 

completing the annual report forms 

since changes in which emergency 

shutdowns are to be reported could 

have a major impact on what needs to 

be reported. DOMAC also commented 

that information reported on incident 

reports (e.g., emergency shutdowns) 

should not be repeated on annual 

reports. DOMAC maintained that 

PHMSA has not made a good case for 

the need for reporting by LNG facility 

operators and those problems in other 

sectors should not be the basis for 

requiring reporting by LNG operators. 

DOMAC suggested that PHMSA should 

convene an LNG data team to design 

forms to be used to report LNG 

incidents because the reporting proposal 

and related forms demonstrate a lack of 

knowledge of LNG facilities. DOMAC 

further suggested that facility data 

should be automatically populated on 

incident report forms from information 

available in the Pipeline and LNG 

Operators’ Registry. SWGas and Paiute 

suggested that PHMSA should partner 

with FERC or states to get LNG 

information to eliminate duplicate 

reporting. These operators also claimed 

that a form is not needed for safetyrelated condition reports because such 

reports at LNG facilities are rare. 

Other commenters raised concerns 

related to how the definition of an 

incident in § 191.3 apply to LNG 

facilities. A principal concern of these 

commenters was the proposed 

requirement that all emergency 

shutdowns be reported as incidents, 

except those resulting from 

maintenance. AGA, INGAA, NEGas, 

Northern, Northwest Natural Gas 

(NWN), BG&E, National Grid, and 

MidAmerican would all limit reporting 

to actual emergencies, noting that not all 

emergency shutdowns are safetysignificant events. MidAmerican 

suggested that requiring such reports 

would discourage operators from 

installing aggressive emergency 

shutdown systems. DOMAC claimed 

that the exclusion for maintenance is 

unnecessary because the preamble of 

the 1984 rulemaking that required 

telephonic reporting of emergency 

shutdowns stated that only actual 

emergencies needed to be reported. 

DOMAC also maintained that the 

concept of a leak in piping and 

equipment is not applicable to an LNG 

facility. BG&E would similarly eliminate 

rollover events as not safety-significant. 

SWGas and Paiute would delete from 

the definition of an incident any 

reference to refrigerant gas because this 

is not gas in transportation and not 

subject to PHMSA’s jurisdiction. 

Piedmont asked for clarification as to 

whether the volume release or 

explosion/fire criteria apply to LNG 

facilities. 

SWGas and Paiute noted that use of 

some terms differs between pipelines 

and LNG facilities and that terms used 

for LNG need to be accurately defined. 

NiSource Distribution Companies 

(NISource Distribution) suggested that 

because LNG is a ‘‘chemical of interest’’ 

for terrorist protection, PHMSA and the 

Department of Homeland Security 

should discuss what information is to be 

collected and made public. 

Response 

PHMSA is not persuaded that relative 

rarity of incidents at LNG facilities 

means that reports of these events are 

not needed. Such reports may be 

submitted rarely, but they will provide 

valuable data concerning safetysignificant events and conditions that 

may occur. The existence of a reporting 

requirement or a related form will 

impose no burden on LNG operators 

that do not experience incidents. 

PHMSA agrees with DOMAC that it is 

not necessary to collect information on 

annual reports that are obtained via 

incident reports. PHMSA has omitted 

reports of emergency shutdowns from 

the annual report form, as these will be 

reported as incidents. (As discussed 

below, PHMSA is withdrawing the 

proposed safety-related condition report 

form at this time). 

PHMSA recognizes that major 

changes occur infrequently at individual 

permanently-located LNG facilities. At 

the same time, some LNG facilities are 

temporary or mobile, and there has been 

unprecedented expansion in the number 

of LNG facilities. It is no longer practical 

for PHMSA to manage its oversight of 

LNG facilities based on recalled 

knowledge. Data is needed, and annual 

reports are the vehicle by which this 

data will be collected and kept current. 

PHMSA has designed its form and will 

design its on-line reporting to allow the 

operator of an individual LNG facility to 

indicate that data reported in the 

previous year has not changed, in which 

case the operator will not need to repeat 

the information. This will minimize the 

reporting burden for operators of 

facilities that do not experience 

changes. 

PHMSA does not agree with DOMAC 

that the forms proposed for LNG 

reporting represent little knowledge of 

LNG facilities and systems. The 

proposed forms were based, in large 

part, on forms that have been used for 

reporting LNG events in the State of 

Texas for many years. PHMSA believes 

these forms are suitable for use, but 

PHMSA recognizes that these forms, as 

for any form, could likely be improved. 

PHMSA will consider DOMAC’s 

proposal to convene an LNG data team 

to review the forms as a subsequent 

effort but does not consider it necessary 

to take this step before implementing a 

reporting requirement for LNG facilities. 


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PHMSA notes that problems in other 

sectors have not formed the basis for 

requiring reporting of LNG incidents. 

PHMSA has focused on LNG in this 

effort. The criteria defining significant 

consequences apply equally to LNG and 

to pipelines. An event that causes a 

death, serious injury, or significant 

property damage is significant whether 

it occurs on a pipeline or at an LNG 

facility. LNG emergency shutdowns 

have long existed as an incidentdefining criterion. The change here is 

that PHMSA is now requiring written 

reports for LNG incidents that 

previously required only telephonic 

reports to NRC. This is part of PHMSA’s 

increased data focus. PHMSA intends to 

base future actions on its analysis of 

data concerning actual safety 

performance. Additional data 

concerning LNG incidents, even if rare, 

is important to support this goal. 

PHMSA has revised the definition of 

an incident in § 191.3 to clarify that 

actuation of an emergency shutdown 

system at an LNG facility that results 

from causes other than an actual 

emergency does not constitute an 

incident. This will eliminate the need to 

submit incident reports for shutdowns 

that result from maintenance, 

inadvertent actuations and signals, and 

any other emergency shutdown that 

does not result from an actual 

emergency. PHMSA has also deleted 

rollovers as an incident criterion. 

PHMSA agrees that these changes will 

focus reporting on events with safety 

significance. PHMSA doubts, however, 

that LNG operators would not install 

systems that aggressively protect their 

facility investment solely because of a 

requirement to report safety system 

actuations. 

PHMSA has not deleted reference to 

a release of refrigerant gas. PHMSA 

acknowledges that this is not gas in 

transportation, but the facility in which 

it is used is regulated. Release of 

refrigerant gas could represent a failure 

within that facility. If that failure results 

in consequences significant enough to 

trigger one of the incident reporting 

criteria, then that event needs to be 

reported. The volume release criterion 

applies to LNG facilities, as modified, to 

include only unintentional gas loss. In 

response to comments, we have 

eliminated the proposed fire or 

explosion criterion. 

PHMSA agrees with DOMAC that it 

would reduce operator burden, and 

likely improve data consistency/quality, 

if information in the Operator 

Identification (OPID) Registry was 

automatically populated into incident 

forms based on the entered OPID. At 

present however, the data that PHMSA 

has concerning OPIDs is not of 

sufficient quality to do so. This will 

change as operators validate the 

information (discussed below). PHMSA 

will consider a change to its on-line 

reporting system, once validation is 

completed, to implement the suggested 

change. 

In response to comments about 

consistency in definitions of terms, 

PHMSA has made every effort to make 

the definitions in forms and instructions 

for LNG reporting accurate and 

consistent. 

PHMSA regularly consults with the 

Department of Homeland Security 

regarding security concerns about data 

made available to the public. PHMSA 

will include LNG data in these 

discussions. 

(5) Creating a National Registry of 

Pipeline and LNG Operators 

49 CFR 191.22 and 195.64 

Proposal 

In the NPRM, PHMSA proposed to 

require all pipeline operators and LNG 

plant or LNG facility operators obtain an 

OPID from PHMSA. This proposal also 

would require operators to use this 

OPID for all submissions (NPMS, annual 

report, accident, incident, safety-related 

condition etc.) to PHMSA. PHMSA also 

proposed that an operator notify 

PHMSA at least 60 days in advance of 

certain profile or other changes to its 

facilities which could impact public 

safety. Such changes would have 

included any of the following activities 

for an existing or new pipeline, pipeline 

segment, pipeline facility, LNG plant, or 

LNG facility: 

• A change in the operating entity 

responsible for operating an existing 

pipeline, pipeline segment, or facility. 

• A change in the operating entity 

responsible for managing or 

administering a safety program (such as 

an IM or Corrosion Prevention Program) 

covering an existing pipeline, pipeline 

segment, or facility. 

• The acquisition or divestiture of 50 

or more miles of an existing regulated 

pipeline or pipeline segment. 

• Any rehabilitation, replacement, 

modification, upgrade, uprate, or update 

costing $5 million or more. 

• The construction of ten or more 

miles of a new hazardous liquid or gas 

transmission pipeline facility, or other 

construction project costing $5 million 

or more. 

• The construction of a new LNG 

plant or LNG facility, or the sale or 

purchase of an existing LNG plant or 

LNG facility. 

A National Registry of Pipeline and 

LNG Operators will serve as the 

storehouse for the reporting 

requirements for a regulated operator. 

Essential to the effectiveness of 

PHMSA’s oversight is the ability to 

monitor and assess the performance of 

the regulated community—examining 

both discrete performance as well as 

historical trending over time. The single 

greatest challenge to PHMSA’s ability to 

track performance, over time is the 

dynamic nature of the regulated 

community itself. Due to conversions of 

service, new construction, 

abandonments, or changes in 

operatorship that occur during 

divestitures, acquisitions, or contractual 

turnovers, operators’ asset profiles often 

change year-to-year, rendering historical 

trending inaccurate. Currently, PHMSA 

does not receive any alerts, information, 

or notification of these types of changes 

and we lack any mechanism to track or 

capture these changes when they occur. 

As a result, PHMSA’s ability to 

accurately portray and assess the 

performance of individual operators is 

severely compromised, with the 

situation deteriorating over time as 

operating and asset changes accumulate 

and compound. 

Additionally, there is an increased 

burden to industry and to PHMSA in 

tracking and maintaining potentially 

numerous OPID’s for the same 

company. Some companies accumulate 

a large number of OPID’s, often 

inadvertently, as the company reports 

across a variety of lines of business (e.g., 

operators may use separate OPID’s for 

reporting their user fee mileage, safetyrelated conditions, NPMS submissions, 

incidents, and annual infrastructure and 

IM data.) The proposed National 

Registry of Pipeline and LNG Operators 

will facilitate the use of one OPID across 

a company’s reporting requirements for 

a given set of pipeline segments or 

facilities thereby reducing the burden 

on both PHMSA and industry for 

tracking these multiple, duplicative 

OPIDs. 

Comments 

Many comments concerning the 

proposed OPID Registry addressed the 

proposal to require 60-days advance 

notice of certain events that can change 

the nature of the operator. INGAA, API, 

AOPL, and many operators commented 

that many of the events for which 

notification was proposed are business 

transactions that must remain 

confidential until they occur. 

Sometimes, this is dictated by 

requirements of the Securities and 

Exchange Commission or other 

agencies. Commenters also noted that 

even non-confidential changes may be 

delayed or modified before 


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implementation, causing schedules to 

be delayed. INGAA and Piedmont 

suggested that annual reporting of 

changes should be sufficient and that 

per-event notification should not be 

required. They also suggested that 

PHMSA should obtain information 

currently reported to FERC, which 

duplicates some of the information 

proposed for the Registry. AGA, Atmos, 

and BG&E recommended deleting the 

proposed notification requirements 

because we had not articulated the need 

for the information. API and AOPL also 

asked that PHMSA explain the need for 

notifications. TPA suggested deleting 

certain notification elements. AGA, 

NiSource Distribution, and NWN noted 

that the information is already reported 

annually to NPMS or on other forms. 

SWGas sought an exemption for 

distribution pipeline operators from the 

notification requirements, contending 

that PHMSA has no authority to regulate 

the costs involved and that a 

relationship to safety is not obvious. 

Commenters also expressed concern 

about the extent of information that 

would be required in notifications. 

Since the proposed notification form 

was not placed in the docket, AGA, 

Atmos, and BG&E claimed that they 

cannot estimate the burden notification 

would entail. API and AOPL suggested 

that PHMSA should identify the 

information to be included in 

notifications and provide an additional 

opportunity to comment. NiSource 

suggested that a form be developed for 

this purpose. SWGas and Paiute noted 

it was unclear how operators are to 

make required notifications. Atmos and 

TPA suggested that the proposed 

notification requirements should be 

delayed while PHMSA seeks additional 

comments. 

Other comments in this area 

addressed concerns with specific 

elements of the proposed notification 

requirements: 

• API and AOPL suggested that 

notification should be required for 

acquisition of a pipeline system rather 

than a pipeline facility because this is 

more consistent with the definitions in 

§ 195.2. 

• El Paso, SWGas, and Paiute 

suggested that additional guidance was 

needed concerning how to treat multiyear construction events for notification 

purposes. NiSource suggested that 

clarification was needed on how to 

address the costs for multi-year projects 

and further suggested that reporting for 

this criterion be moved to the annual 

report. 

• AGA, API, AOPL, and numerous 

pipeline operators expressed concerns 

about the proposed notification 

requirement for rehabilitation, 

replacement, modification, upgrade, 

uprate, or update or construction of a 

new pipeline facility costing $5 million 

or more. They suggested deleting the 

dollar criterion completely, given that it 

is not indexed for inflation and would 

be likely to capture smaller projects in 

future years. They would rely solely on 

notification of construction of some 

threshold of miles of pipeline. El Paso 

and Spectra suggested increasing the 

threshold from $5 million to $10 

million, noting that the cost of 

materials, contractors, and gas loss 

makes a $5 million project a relatively 

minor activity. National Grid would 

index the dollar amounts for inflation 

and limit their applicability to single 

projects vs. programs with multiple 

projects. 

• Other commenters expressed 

concerns with the proposed notification 

requirement for rehabilitation, 

replacement, modification, upgrade, 

uprate, or update. API and AOPL would 

eliminate the proposed requirement 

noting that these changes are intended 

to improve safety, notification does not 

add to safety, and the results of these 

projects would appear in subsequent 

annual reports. Atmos suggested that 

the provision exclude changes that must 

be made in an emergency, since 60-day 

advance reporting would be impractical 

in such circumstances. Mid-American 

would delete this criterion completely, 

claiming it would delay emergency 

repairs. TransCanada suggested 

collecting this information via annual 

report after the events had occurred. 

NAPSR, on the other hand, supported 

reporting under this criterion, noting 

that the information is needed to 

address public concerns and inquiries. 

• Some commenters questioned the 

mileage threshold for notification of 

pipeline construction projects. API, 

AOPL, Atmos, and TXOGA would 

increase the threshold from ten miles to 

50 miles, noting that this is consistent 

with the proposed requirement for 

notifying of acquisition of an existing 

pipeline and that smaller construction 

projects would show up in annual 

reports. IUB suggested that the 

threshold be lowered to five miles 

because information about even small 

construction projects is necessary to 

plan safety inspections. Spectra 

supported 60-day prior notification for 

construction of more than ten miles of 

pipeline or a new LNG plant. 

• INGAA pointed to a discrepancy 

between the preamble and the 

regulatory text on notification of 

changes in the entity responsible for 

major pipeline safety programs. INGAA 

suggested that notification should not be 

required. PST, on the other hand, 

suggested that the discrepancy was an 

omission from the regulatory language 

and that PHMSA add this notification 

criterion. 

• Atmos and TPA suggested 

modifying the criterion for pipeline 

acquisition to refer to pipelines/ 

facilities subject to Parts 192 and 193 

rather than ‘‘regulated by PHMSA.’’ 

They noted that the proposed language 

could lead to confusion for pipelines 

states regulate. 

• IUB requested that the Registry 

capture contact information following 

acquisitions or mergers because this 

information has sometimes been 

difficult to determine. BG&E would 

limit notifications to maintaining 

current contact information. El Paso and 

Spectra suggested that a means to 

update contact information 

electronically would be less 

burdensome than current practice of 

requiring a letter to do so. 

• API and AOPL suggested defining 

‘‘operating entity’’ in the phrase ‘‘[a] 

change in the operating entity 

responsible for an existing pipeline, 

pipeline segment, or pipeline facility, or 

LNG facility.’’ 

• National Grid requested that 

PHMSA work with states toward single 

reporting per state per operator. 

Another major area of comments was 

the perception that PHMSA was 

requiring operators to re-apply for their 

existing OPIDs. API and AOPL 

commented that operators should not 

have to re-enter information when reapplying, but rather record only changes 

in ownership. El Paso, OKIPA, and 

Piedmont objected to requiring 

operators to re-apply when PHMSA has 

not justified such a requirement. OKIPA 

commented further that operators 

should not be required to re-populate 

information based on a new OPID. 

Atmos and TPA commented that 

PHMSA should establish reasonable 

deadlines for operators to complete reapplication and for PHMSA to establish 

a process to keep the information 

current. DOMAC suggested that it 

would be helpful to have more 

information on the content of 

information required when applying for 

an OPID. 

Response 

PHMSA acknowledges that many of 

the changes for which we proposed to 

be notified are business transactions 

that need to be kept confidential and for 

which advance notification is 

impractical. However, not all of the 

proposed notification criteria are in this 

category. New construction by an 

existing operator, including planned 


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modifications, upgrades, rehabilitation 

and uprates, are not business 

transactions requiring such 

confidentiality. PHMSA has modified 

the proposed notification requirement to 

require notification of this type of 

activity 60 days in advance. We will 

require notification of business 

transactions that typically require 

confidentiality within 60 days after the 

event has occurred. 

PHMSA requires advance knowledge 

of planned construction activities so 

that it can plan safety inspections and 

align appropriate inspection resources 

to conduct these inspections. For 

pipeline construction in particular, it is 

important to inspect construction 

activities while they are underway, 

given that the pipeline is often buried 

before being placed in service and it is 

not then practical to inspect the quality 

of construction. NAPSR’s comments 

support this need, noting that states 

exercising safety jurisdiction also 

require advance notice for inspection 

planning. 

PHMSA needs to know of changes in 

operator name, ownership, and 

responsibility for operations to 

adequately track ongoing safety 

performance, and to accurately portray 

safety performance over time, including 

the identification of emerging safety 

trends. Sale of an existing pipeline, or 

the complete acquisition or merger of a 

company may involve the wholesale 

adoption of standing operating and 

safety practices and programs. These 

programs may continue without change, 

or they may be integrated into the 

programs of a new owner. Additionally, 

sale of an existing pipeline may involve 

a complete replacement of staff. 

Personnel responsible for day-to-day 

operation of the pipeline often remain, 

becoming employees of the new owner. 

PHMSA must know when changes in 

responsibility occur, and the parties 

involved, to accurately evaluate and 

trend safety performance data through 

and following periods of change. Some 

information regarding ownership is 

currently reported via NPMS, but NPMS 

does not include all of the information 

PHMSA needs. Similarly, although 

there is duplication in some reporting 

elements with reports required by FERC, 

many pipeline and LNG facility 

operators are not subject to FERC 

reporting requirements making it 

impractical for PHMSA to rely on FERC 

information to serve its operational 

needs. 

Whether ownership change is 

involved or not, sometimes there is a 

change in the primary responsibility for 

managing or administering one or more 

PHMSA-required safety programs. This 

situation arises when existing pipelines 

or LNG Facilities covered by a single 

OPID are part of a common PHMSArequired pipeline safety program or LNG 

safety program which also involves 

other assets covered by other OPIDs. 

(These common safety programs are 

sometimes referred to as ‘‘umbrella’’ 

safety programs.) For PHMSA to 

adequately evaluate these programs and 

accurately document compliance and 

safety performance over time, it must be 

clear, and PHMSA must have a current 

record of which OPIDs (and, by 

extension, which corresponding 

pipelines and/or facilities) are included 

under each PHMSA-required safety 

program, know when these OPIDs 

officially came under these programs, 

and, if and when these OPIDs are ever 

removed from these programs. 

Additionally, this type of notification 

serves to facilitate PHMSA’s resource 

planning and preparations for the 

conduct of its inspections of these safety 

programs. These ‘‘common safety 

program’’ relationships involving 

multiple OPIDs entail a relatively small 

number of pipeline operators, 

something on the order of 10–15% of 

the total number of operators. And they 

also tend to be the larger operators with 

multi-state and multi-system operations 

which, in turn, represent approximately 

70–80% of the total infrastructure 

mileage. As a result, PHMSA’s ability to 

accurately track and monitor a large 

majority of the nation’s most extensive 

pipeline infrastructure will be 

accomplished through this notification 

requirement affecting relatively few 

operators. And this capability to 

understand the make-up of these 

common safety programs over time and 

through operating and/or ownership 

changes is the cornerstone of a more 

data-driven PHMSA organization. 

PHMSA and the states need to know 

of planned construction activities, 

mergers, acquisitions and other changes 

in safety responsibility for distribution 

pipelines as well as transmission 

pipelines. PHMSA is not proposing to 

regulate costs associated with 

distribution pipelines or any other type 

of pipeline, rather, PHMSA is using the 

costs of modifications that do not 

involve construction measurable in 

miles as a trigger for identifying projects 

PHMSA regulates and for which prior 

inspection planning is needed. PHMSA 

has thus not exempted distribution 

pipelines from the notification 

requirements. 

Although the NPRM did not propose 

that operators must re-apply for OPIDs, 

PHMSA recognizes that the NPRM was 

not clear in this regard due to the 

number and nature of comments on this 

topic. PHMSA has modified this final 

rule to make it clear that operators to 

which OPIDs have been assigned prior 

to the effective date of the final rule 

must validate the information associated 

with those OPIDs, and not initiate an 

entire new application or reapplication 

process. This validation must occur 

within six months of the effective date 

of the final rule. Operators must access 

the information currently in PHMSA’s 

records concerning their OPIDs (using 

an on-line, internet-based system) to 

make changes where appropriate, or to 

indicate that the information is correct. 

This will help PHMSA assure that the 

information in its National Registry of 

Pipeline and LNG Operators is a current 

and accurate baseline. The information 

that operators must validate must be 

consistent with the information required 

when applying for a new OPID. This 

information will be on the OPID 

Assignment Request form (referred to in 

the NPRM as the OPID Questionnaire). 

PHMSA has made changes to some of 

the criteria for notification, but has not 

adopted all the changes commenters 

suggested: 

• PHMSA does not agree with API 

and AOPL that notifications for 

acquisitions should refer to pipeline 

systems. Pipeline facility, as defined in 

both §§ 192.3 and 195.2, is a broader 

term that better represents the nature of 

changes in which PHMSA is interested. 

• PHMSA does not agree that 

additional guidance is needed 

concerning multi-year projects. The 

NPRM would not have required annual 

notification but notification prior to 

initiation of a project meeting a 

reporting threshold (dollars or miles) 

regardless of how many years over 

which the project was to be 

accomplished. The final rule retains the 

structure of the proposal in this regard. 

• PHMSA understands the concerns 

commenters expressed about using a 

dollar threshold to identify certain 

projects requiring notification, but sees 

no practical alternative. As described 

above, PHMSA (and states) require prior 

notification of projects for which inprogress safety inspection is 

appropriate. A mileage threshold could 

identify appropriate pipeline 

construction projects, but some 

significant construction projects do not 

involve miles of pipe (e.g., construction 

of a new pump or compressor station). 

PHMSA has increased the dollar 

threshold from $5 million to $10 million 

and has limited its applicability to 

projects not involving line section pipe. 

PHMSA has not indexed this threshold 

for inflation but considers that the 

increase in size and limitation in scope 


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2 §§ 191.25 and 195.56. 

obviates the concerns that smaller 

projects will be unnecessarily reported. 

• PHMSA has also modified the 

reporting criterion for rehabilitation, 

replacement, modification, upgrade, 

uprate or other update to exclude 

changes that must be made on an 

emergency basis from the requirement 

for 60-day prior reporting. The final rule 

requires that operators notify PHMSA of 

emergency projects as soon as 

practicable. 

• PHMSA has retained the 10-mile 

threshold for notification of projects 

involving construction of line section 

pipe. PHMSA recognizes that this is not 

consistent with the requirement to 

notify of acquisition of 50 miles of 

pipeline, but the needs addressed by 

each criterion are different. Acquisitions 

usually involve sizeable pipeline 

facilities; therefore, 50 miles is a 

reasonable criterion, and the 

information is needed to support 

accurate trending of safety data. PHMSA 

and states need information concerning 

pipeline construction to plan safety 

inspections, and a 10-mile construction 

project is large enough that safety 

inspections would be needed. PHMSA 

agrees with IUB that knowledge of even 

smaller construction projects (e.g., IUB’s 

suggested 5-mile criterion) would be 

useful in many cases, but considers 10 

miles appropriate for this notification 

requirement. 

• PHMSA has included a requirement 

to notify it of changes in the entity 

responsible for major pipeline safety 

programs. The failure to include this 

criterion in the proposed regulatory 

language was an oversight. As noted by 

PST, it was discussed in the NPRM 

preamble. 

• PHMSA agrees with Atmos and 

TPA that reference to facilities regulated 

by PHMSA could cause confusion when 

facilities under state regulation are 

involved. PHMSA has modified the 

reference to facilities subject to Part 192, 

and has made a similar change to the 

Registry requirements for hazardous 

liquid pipelines in § 195.58. 

• PHMSA understands the 

importance of updating company 

contact information and of reducing the 

burden for doing so. At the same time, 

PHMSA considers that a change in 

personnel, which could affect ‘‘contact 

information,’’ is too fine a level of detail 

to require notification. Therefore, 

PHMSA has not adopted this 

requirement into the regulations. 

PHMSA will consider modifying the 

National Operator Registry to make it 

available for operators to report 

voluntarily changes in contact 

information. 

• PHMSA has replaced the term 

‘‘operating entity’’ so that the criterion in 

§ 191.22 now refers to, ‘‘[a] A change in 

the entity (e.g., company, municipality) 

responsible for an existing pipeline, 

pipeline segment, pipeline facility, or 

LNG facility.’’ This should alleviate any 

confusion introduced by the use of a 

new term. 

• PHMSA will make available to state 

pipeline safety regulators information 

that it receives through the National 

Operator Registry. States, however, have 

their own information needs, 

requirements, and administrative 

procedures, and PHMSA cannot force 

states to use common reporting 

instruments. 

PHMSA considers it reasonable that 

operators want to know the burden 

associated with obtaining an OPID and 

notification of changes. The NPRM 

referred to an OPID Questionnaire (now 

called the OPID Assignment Request 

form) which was not made available for 

public comment. PHMSA is adopting a 

form for submitting on-line notifications 

to the National Registry of Pipeline and 

LNG Operators. Therefore, PHMSA will 

publish a separate notice in the Federal 

Register providing the public an 

opportunity to comment on the 

proposed forms. 

(6) Requiring Electronic Safety-Related 

Condition and Offshore Pipeline 

Condition Reports 

49 CFR 191.25, 191.27, 195.56, 195.57 

and 195.58 

Proposal 

In the NPRM, PHMSA proposed to 

require an operator of a natural gas or 

hazardous liquid pipeline, or of an LNG 

plant or LNG facility to use a new 

standardized form instead of the freeform Safety-Related Condition reporting 

now used. For offshore pipeline 

conditions, PHMSA requires an operator 

to report certain information within 60 

days after completion of the inspection 

of all its underwater pipelines subject to 

§§ 192.612(a) or 195.413(a). PHMSA 

proposed also to obtain this information 

on a standardized form, filed 

electronically with PHMSA. 

Comments 

Many commenters objected to a 

change from the current requirement for 

when a safety-related condition must be 

reported. Operators must report safetyrelated conditions ‘‘within five working 

days (not including Saturday, Sunday, 

or Federal Holidays) after the day a 

representative of the operator first 

determines that the condition exists, but 

not later than 10 working days after the 

day a representative of the operator 

discovers the condition.’’ 2 The proposed 

language in the NPRM revised this to 

read ‘‘* * * determines or discovers 

***’’ which commenters believed 

eliminated the current distinction 

between five days after determination 

and ten days after discovery of a 

condition. 

SWGas and Paiute claimed that 

because safety-related conditions at 

LNG facilities are rare, a reporting form 

is not needed. These operators also 

asked that PHMSA describe how safetyrelated conditions relate to the 

categories of leak, failure, and incident 

a lack of common understanding affects 

the quality and consistency of reporting. 

With respect to offshore pipeline 

condition reports, Spectra 

recommended not requiring reports for 

inspections that find no exposed pipe. 

INGAA joined with Spectra in 

suggesting PHMSA require a report 60 

days after identifying exposed pipe that 

poses a hazard to navigation. El Paso 

and TransCanada similarly suggested 

treating these inspections like incidents 

or IM inspections for reporting purposes 

(reporting after an event or annually), as 

different criteria/timing for risk-based 

inspections makes comparing data 

difficult. 

Response 

After considering these comments and 

reevaluating our information needs, 

PHMSA has decided to withdraw the 

proposed safety-related condition report 

and associated changes to §§ 191.25 and 

195.56 at this time. PHMSA will 

continue to evaluate its needs and may, 

again, propose changes to requirements 

for submitting safety-related condition 

reports and the information to be 

included in such reports. The proposed 

change to the timing for submission of 

safety-related condition reports was an 

error. PHMSA has withdrawn the 

proposed changes to these sections. 

Safety-related conditions are not 

similar to leaks, failures, and incidents 

and do not fit into a hierarchy with 

these terms. Leaks, failures, and 

incidents are instances in which a 

problem has occurred. Safety-related 

conditions are conditions which make it 

more likely that a failure will occur, 

and, therefore, require additional 

attention from the operator and the 

safety regulator. 

The comments concerning 

underwater pipeline condition reports 

highlighted an inconsistency in the 

current regulations that PHMSA had not 

considered adequately. The 

requirements in §§ 191.27 and 195.57 

require reports 60 days after completion 


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of the inspection of all pipelines subject 

to §§ 192.612(a) and 195.413(a) 

respectively, but the referenced sections 

do not require an inspection of all 

pipelines at a specified period of time. 

Rather, inspections are required to be 

done on appropriate periodic intervals, 

which may vary for different pipelines 

for an individual operator. Therefore, 

there might be no time where inspection 

of ‘‘all’’ pipelines subject to the 

inspection requirements is completed, 

triggering the reporting requirements of 

§§ 191.27 and 195.57. Further, 

§§ 192.612(c) and 195.413(c) require 

prompt notification if an underwater 

pipeline is found to be exposed. 

PHMSA is withdrawing the changes 

proposed in the NPRM to §§ 191.27 and 

195.57. PHMSA is also withdrawing the 

proposed forms related to these 

requirements. PHMSA will consider the 

appropriate manner in which to address 

this inconsistency and consider the 

comments received in this proceeding 

as part of any future rulemaking. 

(7) Merging the Gas Transmission IM 

Semi-Annual Performance Measures 

Report with the Gas Transmission 

Operator Annual Reports 

49 CFR 192.945 and 192.951 

Proposal 

In the NPRM, PHMSA proposed to 

merge the gas transmission IM Program 

semi-annual performance measure 

reports into an operator’s annual report. 

We also proposed changes to the annual 

report. 

The annual report has historically 

collected information on the number of 

leaks from each of seven causes. The IM 

performance requirements include the 

number of leaks, failures, and incidents 

from each of nine causes. This 

difference was the basis for GAO’s 

recommendation in its report (GAO–06– 

946), ‘‘Natural Gas Pipeline Safety: 

Integrity Management Benefits Public 

Safety, but Consistency of Performance 

Measure Should Be Improved’’ that 

PHMSA make changes to allow for 

optimal comparison of performance 

over time and make them more 

consistent with other pipeline safety 

measures. PHMSA modified the annual 

report to collect leak information for the 

same nine causes used in collecting the 

IM performance measure. 

The gas transmission and gathering 

pipeline annual report is now filed by 

state (i.e., an operator whose pipeline 

traverses multiple states files one report 

for each such state). IM performance 

measures have been reported semiannually by program, i.e., one report 

covering all pipelines within an IM 

program regardless of the state in which 

the pipelines are located. The NPRM 

noted that one consequence of 

integrating the IM performance 

measures into the annual report is that 

these measures would now be required 

to be reported by state. 

Comments 

AGA supported the changes to the 

annual report’s cause categories and 

generally supported integrating the IM 

performance measure report with the 

annual report. AGA, joined by NWN, 

noted that this could cause some 

difficulties for operators with IM 

programs that cover multiple OPIDs, 

and who do not now separate IM results 

by individual OPID within the common 

program. These operators suggested a 

means of referring to data reported for 

the OPID under which a common IM 

program is managed rather than 

requiring reporting for each individual 

OPID within the program. 

While AGA agreed that IM 

performance measures should be 

reported annually as part of the annual 

report, they disagreed that these 

measures should be reported by state. 

They claimed that industry does not 

now collect data on this basis and that 

the change will add significant burden 

with no appreciable effect on safety. 

Geo Logic Environmental Services, 

LLC maintained that it would be overly 

burdensome to integrate IM 

performance measures with the annual 

report. 

Response 

Operators must report IM data by 

OPID. PHMSA recognizes that some 

operators manage common IM programs 

which include multiple OPIDs 

representing different system assets. IM 

activities, however, are conducted on 

individual pipeline segments (e.g., in 

the case of assessments) or at individual 

locations along the pipeline (e.g., in the 

case of repairs). Operators therefore 

have this data by OPID. Analyzing data 

by individual OPID provides a better 

opportunity to identify incipient 

problems. Operators with multiple 

OPIDs may have accumulated them by 

acquiring other pipeline systems, and 

problems may result from operation 

under the previous owner(s). Multiple 

OPIDs can also represent different 

pipeline systems of differing vintage 

and differing conditions. Prior treatment 

of pipelines by prior owners or 

problems associated with aging or 

certain types of vintage materials would 

be masked if IM information were 

reported at the common-program level. 

The annual report form requires 

reporting of IM data by individual OPID. 

At the same time, PHMSA needs to 

understand what OPIDs are included in 

common programs so that it can plan IM 

inspections appropriately and so that it 

can properly address any inspection 

findings which result. This information 

will now be collected and maintained as 

part of the National Registry of Pipeline 

and LNG Operators. 

The issue of reporting IM information 

by state also affects proposed changes to 

hazardous liquid pipeline annual 

reports and is discussed below. The 

reporting burden is lessened, because 

reporting will be required annually vs. 

semi-annually. PHMSA has included 

this integration in this final rule. 

(8) Modifying Hazardous Liquid 

Operator Telephonic Notification of 

Accidents Reporting Requirement 

49 CFR 195.52 

Proposal 

In the NPRM, PHMSA proposed to 

require operators to have a procedure to 

calculate and provide a reasonable 

initial estimate of released product in 

telephonic reports to the NRC. PHMSA 

also proposed to require operators to 

provide additional telephonic reports to 

the NRC if significant new information 

becomes available during the emergency 

response phase of a reported event. This 

proposal was based in part on a 

recommendation from the NTSB that 

PHMSA modify 49 CFR 195.52 to 

require pipeline operators to have a 

procedure to calculate and provide a 

reasonable initial estimate of released 

product in the telephonic report to the 

NRC (NTSB Safety Recommendation 

P–07–07). NTSB also recommended that 

the hazardous liquid regulations require 

pipeline operators to provide an 

additional telephonic report to the NRC 

if significant new information becomes 

available during the emergency 

response (NTSB Safety 

Recommendation P–07–08). 

Comments 

API, AOPL, TransCanada, and TPA 

noted that estimates made quickly for 

immediate reports are subject to error. 

These commenters requested that 

PHMSA include a provision holding an 

operator harmless for over-or-under 

estimates in its initial reports. API, 

AOPL and TXOPA recommended 

placing the requirement for a procedure 

to estimate release volumes in 

§ 195.402, ‘‘Procedural manual for 

operations, maintenance, and 

emergencies’’ rather than in the 

reporting requirements of § 195.52. 

TransCanada and TXOGA requested 

that PHMSA provide guidance on what 

would constitute a significant change in 

information necessitating a follow-up 


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report to NRC. API, AOPL, OKIPA, and 

TXOPA suggested revising the 

regulatory text to limit the requirement 

for subsequent reports to situations in 

which an operator has a reasonable 

basis for significant revision of reported 

estimates. PST recommended requiring 

subsequent reports to be submitted ‘‘at 

the earliest practical moment’’ as is now 

required for initial reports. 

API and AOPL commented that there 

is no mechanism to amend or rescind an 

NRC report and that one should be 

provided. TXOGA suggested that 

original and subsequent reports be 

retained by PHMSA for subsequent 

review and analysis. 

Response 

PHMSA recognizes that estimates of 

release made quickly for immediate 

reports are subject to error. Not all 

information can be known immediately 

with accuracy. Calculations must be 

based on assumptions, and those 

assumptions may not be correct. Still, 

information is needed quickly to 

estimate the scope of a problem and 

allow response by appropriate agencies/ 

resources. This is why immediate 

reports to NRC are required. Operators 

are expected to make their best effort in 

making their initial estimates of release. 

Using a procedure to make those 

estimates should help improve their 

accuracy by allowing decisions 

concerning how estimates are to be 

calculated to be made through 

deliberative pre-planning rather than in 

haste after a major event. PHMSA has 

not modified this final rule to hold 

operators harmless for incorrect 

estimates, but would exercise 

appropriate discretion in any 

enforcement action that might result 

following an event reported to NRC in 

which a good faith effort was made. 

Whether to place the requirement that 

operators have a procedure to estimate 

releases in §§ 195.402 or 195.52 is a 

matter of preference. PHMSA can see 

how some might consider that this 

requirement should be grouped with 

other requirements to have procedures. 

In the NPRM, PHMSA chose to 

incorporate this requirement into the 

provision requiring that reports be made 

to NRC, as recommended by NTSB. 

PHMSA has retained that choice in this 

final rule. 

PHMSA does not agree that it is 

necessary to state in the regulation that 

an additional report is required for new 

information that provides a ‘‘reasonable 

basis’’ for modifying prior estimates. The 

proposed rule already limited the 

requirement for subsequent reports to 

instances in which ‘‘significant’’ new 

information becomes available. The 

proposal did not require a supplemental 

report for ‘‘any’’ new information. 

PHMSA considers that this qualifies the 

requirement sufficiently to allow 

operators to use judgment in deciding 

whether new information provides an 

appropriate basis for a supplemental 

report. PHMSA previously published 

guidance concerning changes that 

would be significant enough to justify a 

supplemental report to NRC. This 

guidance may be found in Advisory 

Bulletin ADB–02–04, published in the 

Federal Register on September 6, 2002 

(67 FR 57060). 

Immediate reports are made to NRC, 

not to PHMSA. PHMSA has no 

authority to change NRC processes, 

including establishing or changing any 

mechanism to amend or rescind a report 

or governing which data will be retained 

for subsequent analysis. Such changes 

are beyond the scope of this proceeding. 

PHMSA understands that NRC’s current 

practice is not to remove reports from its 

database. 

(9) Requiring Operators of Hazardous 

Liquid Pipelines to Report Pipeline 

Information by State on the Annual 

Report for Hazardous Liquid Pipelines 

49 CFR 195.49 

Proposal 

In the NPRM, PHMSA proposed to 

require operators of hazardous liquid 

pipelines to submit certain 

infrastructure and IM data separately for 

each state a pipeline traverses. 

Comments 

API, AOPL, TXOPA, TPA, Spectra, 

and TransCanada objected to the 

proposal to collect information by state. 

TransCanada would allow collection of 

infrastructure data (e.g., miles of 

pipeline) on this basis. These 

commenters noted that pipelines 

operate as systems and not by state; 

therefore, operators have no business 

reason to collect data on a by-state basis 

and do not currently do so. The 

commenters contended that given that 

the elements to be reported cross state 

lines, it would be unreasonably 

burdensome to require that the data be 

collected on a by-state basis. API and 

AOPL contended that contrary to the 

statement in the NPRM preamble which 

stated that the industry data team 

generally supported collection of data 

by state, is inaccurate. API and AOPL 

noted that in the 2004 rule that added 

the requirement for the annual report 

PHMSA acknowledged in its response 

to comments that mileage of hazardous 

liquid pipelines in each state is already 

available in the NPMS and that it was 

examining additional enhancements to 

NPMS that would allow collection of 

additional state-by-state information 

without imposing additional burden on 

operators. API and AOPL would limit 

collection of data by state to intrastate 

systems (for which an annual report 

would generally address only one state). 

API and AOPL claimed that the 

Regulatory Analysis supporting the 

NPRM was neither reasonable nor 

reliable because it did not consider the 

additional burden imposed by reporting 

information separately for each state. 

OKIPA suggested that PHMSA obtain 

state based information from the states 

exercising jurisdiction. PST supported 

obtaining additional information on a 

by-state basis as this would increase 

PHMSA’s ability to oversee state 

pipeline regulatory activities. 

Response 

This issue was discussed at some 

length during the Advisory Committee 

meeting discussed below. At that 

meeting, PHMSA agreed that it would 

be reasonable to roll up IM information 

nationally and to limit by-state reporting 

in the annual report for gas transmission 

and gathering pipelines and hazardous 

liquid pipelines, to infrastructure 

information. The Committees supported 

that approach. PHMSA has modified the 

proposed revision to the hazardous 

liquid pipeline annual report form along 

these lines and has revised this final 

rule to require reporting by state only 

for those parts of the form that indicate 

such reporting is required. PHMSA 

acknowledges that some information is 

available in NPMS by state, but all of 

the desired data is not. The NPRM 

discussed the difficulties involved in 

changing NPMS and PHMSA’s 

uncertainty about each operator’s ability 

to provide additional data via that 

system. PHMSA concludes that 

obtaining this information through 

NPMS is not practical at this time. 

It is not practical to obtain state 

information from the states, as suggested 

by OKIPA. State reporting requirements 

vary. Additionally, states only exercise 

jurisdiction over intrastate pipeline 

systems. The only means to obtain 

consistent data for all pipelines is via a 

Federal requirement. 

With respect to PST’s suggestion that 

additional information by state would 

help PHMSA oversee state pipeline 

safety regulatory programs, PHMSA has 

the information it needs for this 

purpose. Some information will be 

reported by state via the annual report, 

as modified. PHMSA also obtains 

additional information directly from 

states that it uses in its oversight of state 

programs. 


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(10) Removing/Revising Obsolete 

Provisions 

49 CFR 191.19, 191.27, 195.57 and 

195.62 

Proposal 

In the NPRM, PHMSA proposed to 

remove or revise several provisions in 

light of the proposal to require 

electronic submission of all reports. 

These provisions were as follows: 

• Remove § 191.19, which advises 

operators they may obtain, without 

charge, copies of paper report forms and 

reproduce the forms. 

• Remove §§ 191.27(b) and 195.57(b), 

which require mailing hard copies of 

Offshore Pipeline Condition reports. 

• Revise § 195.54 to remove the 

option to file an accident report by 

facsimile. 

• Remove § 195.62, which requires 

operators to maintain an adequate 

supply of forms that are a facsimile of 

DOT accident report forms so that the 

operator may promptly report an 

accident. 

The NPRM also indicated that hard 

copies of forms would continue to be 

available on PHMSA’s Web site at 

http://phmsa.dot.gov/pipeline. 

PHMSA received no specific 

comments on these removals/revisions 

and, therefore, we are adopting these 

removals/revisions as proposed. 

(11) Updating OMB Control Numbers 

49 CFR 191.21 and 195.63 

Proposal 

In the NPRM, PHMSA proposed to 

update several sections to add new 

OMB control numbers for the new forms 

(and information collection) proposed 

in the NPRM. 

PHMSA received no public comments 

concerning these changes and have 

adopted them as proposed. 

IV. Comments on Forms 

In addition to comments concerning 

the proposed rule, PHMSA received 

comments on the related forms. 

Comments on the Annual Report for Gas 

Transmission and Gathering Pipelines 

Comments 

INGAA, API, AOPL, and TPA 

commented that reporting mileage to 

three decimal places is more precise 

than is needed or justified. INGAA 

suggested miles be reported to the 

nearest tenth. The other commenters 

would report to the nearest mile. 

Response 

PHMSA agrees that reporting of 

mileage to three decimal places is 

unnecessary. At the same time, PHMSA 

notes that there are some pipelines less 

than one mile in length and for which 

it would be unclear whether zero or one 

should be reported if reporting were by 

mile. PHMSA has revised the form to 

allow reporting to one decimal place 

and has indicated that rounding to the 

nearest mile is allowed. 

The annual report describes the status 

of a pipeline at the end of the reporting 

year and/or events that occurred during 

that year. Gathering lines that become 

regulated during a year should be 

reported as part of infrastructure on that 

year’s annual report. Regulated events 

(e.g., incidents) that occur during the 

year and following the date on which 

the lines become regulated should also 

be reported. 

Part A—Operator Information 

NAPSR would add CO2 to the list of 

commodities given that transport of CO2 

as a gas is likely to become more 

prevalent with forthcoming carbon 

sequestration projects. SWGas and 

Paiute suggested defining ‘‘assets,’’ as 

used in Part A. 

INGAA and TPA recommended 

deleting the last boxes in question 8, 

‘‘does this report represent a change 

from last year’s final reported numbers 

for one or more of the following parts:’’ 

They contended that virtually all 

operators will experience one or more of 

these changes and that the rare case 

where none of the boxes would be 

checked does not warrant the 

inconvenience for others to respond. 

SWGas and Paiute requested clarifying 

the scope of changes that would trigger 

a response in question 8. NiSource 

commented that operators who 

experience no changes should not have 

to complete the remainder of the form. 

NiSource reads the form to indicate that 

operators with changes must complete 

only those sections for which changes 

affect the reported data while operators 

who do not experience any changes 

must complete the entire form. TPA 

noted that spaces are needed for 

operator Headquarters’ state and zip 

code. 

Response 

PHMSA recognizes that carbon 

sequestration projects are likely to result 

in transport of carbon dioxide in 

gaseous form. At present, however, 

PHMSA does not have jurisdiction to 

regulate transportation of carbon 

dioxide as a gas. Legislative change 

would be required to establish 

jurisdiction; therefore, PHMSA cannot 

accept NAPSR’s suggestion to add CO2

as a gas to the list of commodities 

transported. 

PHMSA accepts that the term ‘‘assets,’’ 

could be confusing and has replaced 

this term with ‘‘pipelines’’ and ‘‘pipeline 

facilities,’’ both of which are defined in 

the regulations. 

PHMSA has revised Question 5 and 

the instructions to resolve confusion 

concerning how to report IM data. IM 

data is to be reported by individual 

OPID and not as part of a common 

program under one OPID, as discussed 

above. The revised question simply asks 

whether the pipelines and pipeline 

facilities under the OPID being reported 

are under an IM program. If not, the 

form indicates which parts (i.e., those 

collecting IM-related data) the operator 

need not complete. 

PHMSA has revised question 8 in 

response to the comments on this 

portion of the form and to comments 

made about a similar question on the 

hazardous liquid pipeline annual report 

form. PHMSA has combined the blocks 

operators would use to report changes 

due to mergers and acquisitions, as 

suggested by API and AOPL, for the 

hazardous liquid form because these 

two terms can be confused and there is 

no reason to report the events 

separately. PHMSA has also revised 

question 8 to indicate that operators 

who have experienced no changes need 

not complete many sections of the form 

for which data would be identical to 

that reported in the prior year. (Note 

that this is not applicable to reporting 

for calendar year 2010 given that the 

data on this form will be reported for 

the first time during that year). PHMSA 

concludes this will reduce the reporting 

burden for operators who do not 

experience changes to their pipeline 

systems. Operators who experience 

changes due to any of the reasons listed 

in question 8 must complete the entire 

form. 

PHMSA notes the confusion regarding 

the intent of question 8. In particular, 

INGAA and TPA claimed the question 

was unnecessary because virtually all 

operators would experience one of the 

listed changes during any given year. 

PHMSA advises that simply 

experiencing such a change does not 

lead to a ‘‘yes’’ answer to this question. 

Instead, ‘‘yes’’ indicates that the 

numbers reported on the prior year’s 

form have changed as a result of one of 

the listed events. PHMSA intends to use 

the responses to this question to 

understand why data that was reported 

changed for a given operator from yearto-year and to help prioritize its 

inspection activities. In addition, 

eliminating the need for operators who 

have not experienced changes that affect 

data reported previously to report the 

same data again will improve data 


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quality by avoiding collection of 

inaccurate data due to data entry errors. 

For example, operators who experience 

a modification to their pipeline (one of 

the listed changes) but for whom that 

modification results in no change to the 

numbers reported on the prior year’s 

annual report would answer ‘‘no’’ to 

question 8 and would not be required to 

complete the bulk of the form (except 

for 2010). PHMSA has made editorial 

changes to the form to emphasize this. 

PHMSA has made a number of other 

editorial corrections to the form, 

including adding space for operator 

headquarters’ state and zip code. 

Part B—Transmission Pipeline HCA 

(High Consequence Area) Miles 

INGAA suggested deleting the number 

of offshore miles because there are not 

enough miles of offshore transmission 

pipeline to make the data pertinent. 

Response 

PHMSA will require reporting of 

offshore HCA miles. Although there 

may be few such miles, they do exist 

(e.g., an offshore platform that includes 

a transmission line and is occupied by 

20 or more persons). Operators who 

have no offshore HCAs, which PHMSA 

recognizes will be most operators, may 

enter zero in this field. 

Part C—Volume Transported in 

Transmission Pipelines Only in Million 

Standard Cubic Feet (mmscf)-Miles Per 

Year 

AGA contended that it would be 

unreasonably burdensome to report 

volume transported. INGAA and Spectra 

maintained that because transported gas 

does not necessarily traverse an entire 

pipeline reporting volume-miles is 

impractical and PHMSA should use 

data already collected by FERC. Atmos, 

TPA, SWGas, and Paiute commented 

that this information does not appear 

relevant to pipeline safety and would be 

difficult to collect, particularly for bidirectional pipelines. GPTC and Nicor 

commented that this element is 

impractical for distribution pipeline 

systems in which only a small portion 

of pipeline is defined as transmission 

due to operating pressure. They noted 

that it is impractical to determine how 

much gas flowed through these limited 

portions of a pipeline system and 

questioned the safety need for the 

information. NiSource and NWN also 

claimed that it is unclear why PHMSA 

needs this information and that it may 

be proprietary or is already available 

from FERC. TPA suggested that, if we 

retain this section, we specify the 

reporting basis (e.g., standard 

temperature and pressure) because some 

states (e.g., Texas) require reporting of 

volumes under other pressure bases. 

Response 

PHMSA recognizes that it is difficult 

to determine the amount of gas 

transported, in mmscf-miles, for 

pipelines with multiple locations at 

which gas can be collected and 

delivered. At the same time, an 

indication of the total volume of gas 

transported will be useful data for 

PHMSA’s analysis of pipeline safety 

performance. Such information can, for 

example, be used to normalize analyses 

of different events. PHMSA has revised 

this part to require reporting of the total 

volume of gas transported under the 

reporting OPID during the reporting 

year for operators who do not operate 

their transmission lines as part of a 

distribution pipeline system. PHMSA 

recognizes that this will not accurately 

represent the volume carried in only 

portions of interstate gas transmission 

systems, but PHMSA believes this 

strikes an appropriate balance between 

the burden to calculate mmscf-miles 

and the need for an overall measure of 

relative activity of different OPID 

transmission volumes. PHMSA will use 

this information with care. 

PHMSA also recognizes that it would 

be particularly difficult for operators of 

distribution pipeline systems in which 

only a portion of the pipeline is 

classified as transmission to estimate 

the volume of gas carried by their 

transmission pipelines. PHMSA has 

revised this part to eliminate the need 

to report volume transported for 

operators who operate transmission 

pipelines as part of a distribution 

pipeline system. Volume information 

for these pipelines will be collected on 

the distribution pipeline system annual 

report, which PHMSA is currently 

revising. 

PHMSA notes that the proposed 

instructions for this part included a 

definition of mmscf as million standard 

cubic feet and noted that standard 

conditions are ‘‘normally set at 60F and 

14.7 psia.’’ PHMSA has deleted the word 

‘‘normally’’ to make clearer that these are 

the conditions at which volume is to be 

reported. PHMSA has also revised the 

proposed instruction to reflect a 

pressure of 14.73 psia to be consistent 

with how FERC describes standard 

conditions. 

Part F—Integrity Inspections Conducted 

and Actions Taken Based on Inspection 

INGAA commented that PHMSA 

should make clear that only testing 

conducted as a result of IM 

requirements should be reported. 

AGA contended that PHMSA has not 

justified collecting more detailed IM 

performance data. SWGas and Paiute 

claimed that PHMSA does not need 

additional data to judge the adequacy of 

IM. National Grid does not support 

reporting information beyond the 

number of immediate and scheduled 

repairs in HCAs, because additional 

data would cause confusion due to 

overlapping inspection techniques. 

Atmos and TPA commented that 

reporting the number of assessments by 

tool type would overstate the mileage 

assessed compared with other 

assessment types given that operators 

typically run multiple tools over the 

same mileage as part of a complete 

assessment. AGA and NWN claimed 

that collecting repair data by assessment 

technique would be burdensome with 

no apparent safety benefit, and that 

information concerning assessments 

conducted by method has no apparent 

safety value. INGAA, GPTC, and 

NiSource recommended deleting 

questions concerning inspections by 

tool type, contending that separate 

collection is misleading, will lead to 

incorrect mileage totals, and is of 

marginal value. INGAA also would limit 

miles inspected and actions taken for 

hydrotests to HCA miles because that is 

the only area with consistent repair 

criteria. 

Atmos and TPA also maintained that 

reporting the number of conditions 

identified for repair by various 

assessment techniques, particularly 

outside HCAs, will provide no useful 

information given that there are no 

common criteria for when repairs are 

required. AGA argued that repairs 

outside of HCA should not be reported 

because this data serves no safety 

benefit and PHMSA has not justified 

collecting this data. GPTC, NiSource, 

Nicor, NWN, Piedmont, and INGAA 

also supported this position. 

AGA and NWN maintained it would 

be more useful to collect data on 

anomalies identified by assessment 

cycle (e.g., baseline, first re-assessment) 

rather than by tool. 

National Grid noted that because ‘‘one 

year’’ and ‘‘scheduled’’ conditions are 

the same under § 192.933, both terms 

should not be used. GPTC and Nicor 

would clarify that the number of 

anomalies within HCAs (section 2c) 

should be the number repaired. AGA, 

GPTC, NWN, SWGas, Paiute, NiSource, 

and Nicor suggested that consistent and 

more-detailed definitions are needed for 

the terms leak, failure, incident, and 

rupture if consistent reporting is to be 

achieved. They further suggested 

PHMSA consider whether events of this 

type are to be reported based only on IM 


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assessments or from all means by which 

they are identified. BG&E suggested that 

PHMSA conform terms to their use 

elsewhere and specifically use the terms 

‘‘immediate,’’ ‘‘scheduled,’’ and 

‘‘monitored,’’ as used in Subpart O of 

Part 192, to refer to anomalies of 

concern under IM requirements. 

Sempra Energy Utilities (Sempra) 

recommended modifying this part to 

allow an operator to reference another 

OPID for IM data. This would 

accommodate situations in which IM 

activities are managed under a common 

program for multiple OPIDs. NWN also 

noted that IM programs are often run in 

common for multiple OPIDs making it 

difficult to break out the data for 

individual OPIDs. 

GPTC noted that question 5b refers to 

in-line inspection (ILI) even though the 

subject of question 5 is non-ILI 

techniques. NiSource would delete Part 

F5, since it duplicates information 

collected elsewhere on the form. 

Response 

PHMSA does not understand 

completely why INGAA believes that 

only testing conducted as a result of IM 

requirements should be included. If, as 

INGAA suggested ‘‘overtesting’’ (i.e., 

testing of non-HCA miles assessed as 

part of an IM inspection) were included, 

what would be excluded for these 

segments? While the regulations 

establish maximum reassessment 

intervals, they also require that 

operators base their reassessment 

intervals on the identified threats, data 

from the last assessment and data 

integration (§ 192.939). Assessments 

that are conducted at shorter intervals 

than the maximums specified in the 

regulations provide additional data that 

must be considered in data integration 

and thus come under the provisions of 

IM regulations (see the response to 

FAQ–70 on the gas integrity IM Web 

site, http://primis.phmsa.dot.gov/

gasimp, for additional discussion). 

Therefore, all testing on pipelines with 

HCAs must be reported. 

Assessments that are conducted on 

pipelines that do not contain any HCAs 

are a different matter. Such pipelines 

are not covered by the IM provisions of 

the regulations. Operators are not 

required to report data for portions of 

these pipelines that they may assess for 

other reasons. PHMSA will consider 

future regulatory changes to establish 

requirements for reporting assessments 

and repair actions on pipeline segments 

that do not include HCAs. 

Although PHMSA recognizes that 

there are no criteria in the regulations 

for when anomalies outside of HCAs 

must be repaired, PHMSA is aware that 

operators repair many anomalies 

outside of HCAs. PHMSA considers it 

important to understand when such 

repairs are being made and any trends 

(e.g., are the number of repairs 

increasing over time). PHMSA 

recognizes that operators use different 

criteria for these repairs and that the 

data must therefore be used with care. 

This does not mean, however, that the 

data is not meaningful. Any data that is 

indicative of the condition of U.S. 

pipelines has value in PHMSA’s 

analyses and decision making. PHMSA 

disagrees with INGAA’s suggestion that 

repairs performed as a result of 

hydrotests should only be reported 

when they occur within HCA miles. 

Hydrotests identify defects, by causing 

leakage or a rupture, which must be 

repaired and, therefore, provide the 

most consistent ‘‘criteria’’ for repair of 

defects outside HCAs of any assessment 

method. 

Similarly, collecting data by tool type 

and other assessment methods will be 

useful in informing PHMSA decision 

making and in improving PHMSA’s 

understanding of the relative 

effectiveness and extent of use of 

various assessment methods. PHMSA 

recognizes that adding the miles 

assessed by different assessment 

methods provides a result that appears 

to overstate the number of pipeline 

miles actually assessed. Adding miles 

does, however, provide a better 

indicator of the number of miles by 

assessment method. Again, PHMSA 

recognizes that the totals need to be 

used with caution. Still, it will be 

appropriate to use them for some 

purposes, while miles inspected using 

individual tools (also collected in this 

part) or total HCA miles (collected in 

Part B) will be more appropriate for 

other uses. 

PHMSA agrees that it could be more 

useful to collect data on the number of 

repairs in each assessment cycle. The 

effectiveness of IM regulations would be 

demonstrated by a reduced number in 

subsequent reassessments. PHMSA 

considers, however, that it would be 

more difficult to collect and use this 

data. New HCAs on pipelines 

previously assessed make it unclear 

how to differentiate between baseline 

and reassessment, for example. Given 

that operators now collect data per 

integrity assessment method trends in 

this data over time will better reflect the 

relative effectiveness of IM. 

PHMSA has been careful to use terms 

with meanings commonly understood 

within the pipeline industry. The terms 

‘‘leak,’’ ‘‘failure,’’ and ‘‘incident’’ are 

defined in the instructions consistent 

with ASME/ANSI B31.8S and with 

current regulations. PHMSA recognizes 

that these terms are used in other 

situations and will try to ensure 

consistent use on other forms. Use of the 

term ‘‘scheduled’’ to identify some IM 

anomalies is also consistent with the 

regulations and is not redundant with 

‘‘one-year conditions.’’ Section 

192.933(c) requires that operators 

schedule some anomalies for 

remediation consistent with the 

scheduling provisions of ASME/ANSI 

B31.8S, while § 192.933(d)(2) identifies 

some specific anomalies as ‘‘one-year 

conditions.’’ PHMSA has revised the 

section references on the form (which 

both previously referred only to 

§ 192.933) to make this distinction more 

clear. 

PHMSA acknowledges that question 5 

in Part F inaccurately referred to ILI 

inspections. This question is intended 

to address assessments by other 

techniques. PHMSA has corrected this 

error, which eliminates the duplication 

NiSource noted. 

We addressed above in the section on 

‘‘Creating a National Registry of Pipeline 

and LNG Operators’’ comments about 

reporting IM data by individual OPID 

vs. under a common program. 

Part G—Miles of HCA Baseline 

Assessments Completed 

INGAA suggested that this section be 

broken into separate sub-sections for 

each reassessment. Atmos and TPA 

reported that they did not see how 

reporting assessments by vintage was 

useful. Spectra noted that HCA miles 

complicate the treatment of vintage 

given that an assessment by ILI often 

inspects more than just HCA mileage. A 

new HCA within a piggable segment, for 

example, may undergo a baseline 

assessment at the same time that other 

HCAs within the segment are being 

reassessed. 

Response 

At this time, PHMSA agrees that 

collecting data on assessment vintage 

(i.e., first, second, etc.) is not necessary. 

PHMSA may revisit the need for this 

information as part of future activities. 

PHMSA has revised this part to collect 

data on the number of baseline miles 

completed and the number of 

reassessment miles (regardless of 

vintage). PHMSA expects that there will 

be a reduction in the number of 

anomalies identified in reassessments 

vs. initial baseline assessments, and 

needs this data to validate that 

expectation. 


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Part H—Miles of Pipe by Nominal Pipe 

Size 

INGAA noted that the proposed form 

does not allow reporting of odd pipe 

sizes. The form provides for reporting of 

even pipe sizes specified in modern 

standards, but INGAA noted that 

intermediate sizes may exist in older 

systems, particularly for grandfathered 

pipe. INGAA also noted that the largest 

pipe size included in the form is 36- 

inch diameter and pointed out that 

larger pipe is being used/planned for 

some gas transmission pipelines. 

Response 

PHMSA acknowledges that odd pipe 

sizes may exist in some pipeline 

systems, including small diameter pipe 

(e.g., 5-inch diameter) and pipe installed 

in older pipeline systems before pipe 

sizing was standardized. PHMSA has 

modified the form and instructions to 

accommodate reporting of odd pipe 

sizes and to include sizes larger than 36- 

inch diameter. 

Part J—Miles of Transmission Pipe by 

Specified Minimum Yield Strength 

AGA, NWN, SWGas, and Paiute 

commented that reporting pipeline 

mileage by specified minimum yield 

strength (SMYS) would be unduly 

burdensome because records are 

incomplete, grandfathered pipe may not 

fit into standard categories, and 

information technology (IT) changes 

would be needed to track mileage by 

SMYS. These commenters see no safety 

benefit in doing so. Atmos and TPA 

would also delete this section although 

they recognized there could be some 

benefit in reporting for pipelines 

operating under special permits or at 

80% SMYS where special regulatory 

attention may be needed. They 

suggested that targeted reporting for 

these pipelines should be established 

rather than imposing an unjustified 

burden on all pipeline operators. TPA 

claimed that some operators of gathering 

pipelines treat all of their lines as Type 

A rather than determining the 

percentage of SMYS at which they 

operate and that it would be 

unreasonable to require operators to 

make this determination solely for this 

reporting. 

NiSource noted that no allowance is 

made for pipelines operating at an 

unknown percentage of SMYS even 

though the regulations allow operations 

without this determination. For 

example, § 192.739 provides for 

determining a pressure limit for 

pipeline operating at an unknown 

percentage of SMYS. NiSource also 

noted that plastic and iron pipe are 

excluded, even though some 

transmission pipe is constructed of 

these materials. NiSource also claimed 

that the information collected via Part J 

largely duplicates information from Part 

K, miles of pipe by class location. 

INGAA suggested that we eliminate 

blacked-out cells (implying that no 

pipeline should exist in that category) 

and noted that there is no offshore 

transmission pipeline that exceeds 72 

percent SMYS. 

Response 

PHMSA considers this data to be 

important. The thresholds dividing the 

various categories in the table reflect 

regulatory requirements (e.g., change in 

design factors) and PHMSA needs to 

have an understanding of the inventory 

of pipe to which these requirements 

apply. PHMSA notes that INGAA, 

which represents transmission pipeline 

operators who would tend to have 

pipeline across the range of allowable 

percentages of SMYS, did not object to 

reporting this data. Rather, AGA and 

some of its member companies 

expressed concerns. These companies 

generally operate distribution pipeline 

systems. While many of their systems 

include some transmission pipeline, the 

amount is relatively less and most tend 

to operate in the lower percentage 

SMYS categories. Thus, the burden for 

completing this section will be less for 

these companies. 

While the regulations establish design 

thresholds consistent with those in this 

part, existing pipelines do not always fit 

into these neat categories. Pipe that was 

installed prior to the time pipeline 

safety regulations were initially 

established (i.e., pre-1970) may operate 

at maximum allowable operating 

pressures (MAOP) based on historical 

operation prior to that date (so-called 

‘‘grandfathered pipe’’) and this pressure 

is in some cases in excess of 72 percent 

SMYS. Some pipe operates under 

special permits that allow different 

MAOP. Some pipe operates at MAOP 

greater than originally designed due to 

changes in class location and the 

allowance for pressure increase that is 

inherent in § 192.611. PHMSA is not 

persuaded by arguments that it is too 

hard for pipeline operators to acquire 

this data. Pipeline operators should 

acquire this data wherever possible 

because of its importance. Pipe 

operating at a higher percentage of 

SMYS has less safety margin. It is 

important that operators know where 

this pipe is and take this factor into 

account in the risk analyses required by 

IM regulations. 

For these reasons, PHMSA has 

retained this part. PHMSA has made 

changes in response to the other 

comments concerning this part. PHMSA 

has eliminated blacked out cells. As 

discussed above, grandfathering, special 

permits, and other circumstances could 

result in pipe operating at various 

combinations of MAOP and class 

location and PHMSA agrees it is more 

appropriate to allow for data collection 

in all categories. Operators with no pipe 

in individual categories will simply 

enter zero. The revised form allows for 

pipe that operates at an unknown 

percentage of SMYS and for pipelines 

other than steel. PHMSA has also 

deleted the row corresponding to 

offshore transmission pipeline with 

MAOP greater than 72 percent SMYS. 

The information collected in this part 

does not duplicate that in Part K. 

PHMSA agrees that the information in 

the two parts is related. Important 

information will be obtained through 

analyses that compare the information 

obtained in each of these parts. This 

will help PHMSA understand, for 

example, the amount of pipe that 

operates at MAOP higher than initial 

design due to the automatic-increase 

provisions in § 192.611. It is necessary 

to collect the data in both parts to allow 

this kind of correlation to be made. 

Part J applies to transmission 

pipeline. Operators of gathering lines 

need not complete Part J. 

Part K—Miles of Pipe by Class Location 

SWGas and Paiute commented that 

this section appears to replicate Part B 

insofar as it relates to miles in HCA. 

They claimed it could be confusing to 

report miles that are not in an HCA but 

which must be inspected anyway under 

the IM program. 

SWGas recommended that we exempt 

distribution pipeline operators that also 

report on transmission pipeline they 

operate. Many distribution operators 

treat all of their pipeline as Class 3 or 

4 and do not perform analyses to 

determine accurately the class location 

of their transmission pipeline. SWGas 

opposed requiring such analyses solely 

to meet this reporting requirement. 

Response 

PHMSA agrees that reporting HCA 

miles in the IM program in this part 

duplicates Part B and has eliminated 

this section of Part K. 

This part does not require that 

operators perform Class location studies 

if they do not do so for other purposes. 

Operators of distribution pipeline that 

treat all of their pipeline as Class 3 or 

4 should report the mileage that they 

consider to be in each Class. 


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Part L1—Leaks Eliminated/Repaired 

During Year and Failures/Incidents in 

HCA 

Atmos, NWN, and TPA requested 

clarification as to whether leaks 

repaired in IM assessments and reported 

in Part F are also to be reported in this 

part. 

Nicor and NWN suggested 

reorganizing the columns for failure, 

leak, and incident data in order of 

severity to provide clarity and help 

assure consistent reporting. AGA noted 

that the failure category was omitted for 

gathering pipelines. 

NAPSR suggested adding a column 

for unregulated gathering lines, as they 

consider that data should be collected 

for all gathering lines. 

Response 

Operators are to report all leaks both 

in HCAs and outside HCAs. Failures 

and incidents are to be reported for 

HCAs. This is an existing performance 

measure required by § 192.945 (through 

reference to ASME/ANSI B31.8S) that 

has been reported on semi-annual 

performance measure reports. 

PHMSA agrees that reordering the 

columns in order of relative severity 

could improve clarity and has made that 

change. 

While PHMSA agrees with NAPSR 

that it would be beneficial to have data 

for unregulated gathering lines, such 

lines are by definition unregulated. 

PHMSA cannot impose a reporting 

requirement on these pipelines without 

a regulatory change. Such changes are 

beyond the scope of this rulemaking. 

Part N—Certifying Signature 

Atmos and TPA suggested that a 

separate signature block be used to 

certify IM information because the 

proposed form implies certification of 

the entire form, which is not required. 

INGAA noted that the references to the 

parts of the form containing IM 

information, and for which certification 

is required, were incorrect. 

Response 

PHMSA has revised the form to make 

it clearer that executive certification 

applies only to IM information. PHMSA 

will also clarify this in the on-line 

electronic reporting system. 

Instructions 

Atmos and TPA commented that the 

instructions need to reflect electronic 

reporting and address the requirements 

for seeking alternate reporting methods. 

TPA suggested that the instructions 

define interstate pipelines as those to 

subject to FERC jurisdiction ‘‘under the 

Natural Gas Act’’ rather than simply 

‘‘subject to FERC jurisdiction,’’ noting 

that some intrastate pipelines are 

subject to limited FERC jurisdiction. 

NAPSR suggested defining synthetic 

gas. NAPSR also suggested clarifying the 

instructions on counting repaired leaks. 

For example, if a section of pipe with 

leaks is replaced, does PHMSA consider 

that one repair or must the number of 

leaks within the section be reported? 

SWGas and Paiute contended that the 

definition of operator in the instructions 

is inconsistent with the definition in the 

regulations in that it introduces the term 

‘‘substantial control.’’ 

INGAA suggested that the instructions 

for Part F, Question 4 should refer to 

‘‘meeting repair criteria’’ rather than 

‘‘exceeding.’’ INGAA also suggested that 

the instructions for Part G should mirror 

those for Part F. 

SWGas and Paiute suggested that the 

instructions for Part J clarify reporting 

for pipe that is classified as 

transmission under the functional 

aspects of the regulatory definition even 

though it operates at less than 20% 

SMYS. 

Response 

PHMSA has revised the instructions 

to address requirements for applying for 

alternate methods (i.e., non-electronic) 

of data submission and to use the 

statutory definition of interstate 

pipeline from 49 USC 60101. PHMSA 

has included a definition of synthetic 

gas that is consistent with the definition 

in the instructions for the new incident 

report form. PHMSA has also reviewed 

and revised all definitions to be 

consistent with regulations. 

Counting leaks has always been 

problematic. As NAPSR pointed out, 

when a section of pipe is replaced due 

to leakage, an operator could count the 

repair as one repair or as the number of 

leaks in the replaced section. When 

replaced pipe is retired in place, it may 

not be possible to count the number of 

leaks. Operators have previously been 

required to report the number of leaks 

repaired as part of their annual reports. 

Operators should report the number of 

leaks repaired based on the best data 

they have available. For sections 

replaced, but retired in place, operators 

should consider leak survey information 

to determine, to the extent practical, the 

number of leaks in the replaced section. 

PHMSA has made editorial changes 

concerning repair of anomalies 

‘‘meeting’’ repair criteria. INGAA’s 

suggestion that the instructions for Part 

G mirror those for Part F was predicated 

on its recommended expansion of Part 

G so that the parts would be similar in 

content. As discussed above, this 

change is not necessary because we 

have simplified Part G to reflect only 

baseline and reassessment miles, 

regardless of vintage. 

PHMSA does not understand the basis 

for confusion over whether Part J should 

apply to transmission pipelines 

operating at less than 20 percent SMYS. 

The proposed part explicitly included a 

section in the form for pipeline 

operating at less than or equal to 20 

percent SMYS. Nevertheless, PHMSA 

has clarified in the instructions that Part 

J applies to all transmission pipeline. 

Comments on the Annual Report for 

Hazardous Liquid Pipelines 

General Comments 

API and AOPL commented that 

mileage should be reported to the 

nearest mile rather than to three decimal 

places citing a lack of need or 

justification for the proposed level of 

precision. API and AOPL also 

commented that reporting by state 

should be limited to infrastructure data 

(e.g., miles by state) and that by-state 

reporting of IM data should be required 

for intrastate pipelines only because 

interstate hazardous liquid pipelines are 

operated as systems and operators do 

not keep or track data by state. They 

noted that reporting all data by state 

would be a significant increase in 

burden with no corresponding increase 

in safety. 

Response 

PHMSA agrees that reporting of 

mileage to three decimal places is 

unnecessary yet notes that for those 

pipelines less than one mile in length it 

would be unclear whether zero or one 

should be reported, if reporting were by 

mile. PHMSA has revised the form to 

allow reporting to one decimal place 

and has indicated that rounding to the 

nearest mile is allowed. 

PHMSA also agrees that reporting all 

IM data by state is unnecessary. PHMSA 

has revised the form and instructions to 

require that IM data be reported once for 

all interstate pipelines under an OPID. 

We will continue to require data for 

intrastate pipelines to be reported by 

state. 

Part A—Operator Information 

API and AOPL submitted a number of 

comments on this part. They 

recommended that PHMSA— 

• Make explicit the implication in the 

first box of question 5 that lines that 

cannot affect an HCA need not be in an 

IM program. 

• Clarify question 5 regarding how 

information for companies under a 

common IM program is to be collected. 

Specifically, they contended that 


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operators of pipelines that are under a 

common program should not be 

required to be report data that will be 

reported for the OPID under which the 

common program is managed. 

• Delete question 7, which asks 

operators to list the states in which their 

inter- and intrastate pipelines are 

located, since this duplicates 

information collected elsewhere on the 

form. 

• Combine the first two sub-blocks of 

Question 8, Part 3 because mergers and 

acquisitions can be confused. 

• Revise question 4 to add space for 

state and zip code. 

Response 

PHMSA has revised Question 5 but 

has not accepted all of the suggestions. 

While in most cases pipelines that 

cannot affect an HCA are not in an IM 

program, that is not universally true. 

Some pipelines that cannot affect HCAs 

are covered by an IM program as a result 

of special requirements imposed by 

compliance orders or as conditions of a 

special permit, for example. PHMSA 

expects IM data for these pipelines to be 

reported as part of the annual report. IM 

data is to be reported by individual 

OPID and not as part of a common 

program, as discussed above. PHMSA 

has revised question 5 and the 

instructions to make this clear. The 

revised question simply asks whether 

the pipelines and pipeline facilities 

under the OPID being reported are 

under an IM program. If not, the form 

indicates which parts (i.e., those 

collecting IM-related data), need not be 

completed. 

PHMSA has revised question 6. 

Although we received no comments on 

this question, review of the form to 

address other comments revealed that 

PHMSA had omitted biofuels/ethanol as 

a commodity type. On August 10, 2007, 

PHMSA published in the Federal 

Register (72 FR 45002) a determination 

that transport of unblended biofuels by 

pipeline is under its jurisdiction and 

has previously revised the accident 

report form (PHMSA F 7000–1) to 

include this commodity type. Operators 

would select this commodity type in 

question 6 for pipelines that 

predominantly carry unblended 

biofuels. Transportation of biofuels 

blended with refined petroleum 

products would be reported as 

Petroleum Products/Refined Products. 

PHMSA is aware of only a limited 

number of miles of U.S. pipelines in 

Florida and Texas that currently 

transport unblended biofuels, but notes 

that some operators have expressed an 

interest in constructing such pipelines. 

PHMSA has retained question 7. 

There is little burden associated with 

answering these questions given that 

operators are aware of the states in 

which their pipelines are located. 

Answering this question in Part A helps 

position the operator to complete the 

remainder of the form. The answer also 

provides an opportunity for PHMSA to 

cross-check that necessary data is, 

indeed, reported for all appropriate 

states as part of its ongoing efforts to 

assure data quality. 

PHMSA has revised question 8 in 

response to the API and AOPL comment 

and to comments made with regard to 

a similar question on the gas 

transmission and gathering pipeline 

annual report form. PHMSA has 

combined the blocks operators would 

use to report changes due to mergers 

and acquisitions because these two 

terms can be confused and there is no 

reason to report the events separately. 

PHMSA has also revised question 8 to 

indicate that operators who have 

experienced no changes need not 

complete many sections of the form for 

which data would be identical to that 

reported in the prior year. (Note that 

this is not applicable to reporting on 

this form for calendar year 2010 because 

the data will be reported for the first 

time during that year). This will reduce 

the reporting burden for operators who 

do not experience changes to their 

pipeline systems. Operators who 

experience changes due to any of the 

reasons listed in question 8 must 

complete the entire form. 

There has been some confusion 

regarding the intent of question 8. In 

particular, comments submitted with 

respect to the gas transmission and 

gathering pipeline annual report form 

suggested that the question was 

unnecessary because virtually all 

operators would experience one of the 

listed changes during any given year. In 

response, PHMSA notes that simply 

experiencing such a change does not 

lead to a ‘‘yes’’ answer to this question. 

Instead, ‘‘yes’’ indicates that the 

numbers reported on the prior year’s 

form have changed as a result of one of 

the listed events. PHMSA intends to use 

the responses to this question to 

understand why reported data changes 

for a given operator from year-to-year 

and to help prioritize its inspection 

activities. In addition, by eliminating 

the requirement for operators who have 

not experienced changes that affect data 

reported previously to report the same 

data again will improve data quality by 

avoiding collection of inaccurate data 

due to data entry errors. For example, 

operators who experience a 

modification to their pipeline (one of 

the listed changes) but for whom that 

modification results in no change to the 

numbers reported on the prior year’s 

annual report would answer ‘‘no’’ to 

question 8 and would not have to 

complete the bulk of the form (except 

for the reporting of calendar year 2010 

data). PHMSA has made editorial 

changes to the form to emphasize this. 

PHMSA has also changed the form to 

allow state and zip code information to 

be entered for the operator headquarters’ 

address. 

Part C—Volume Transported in BarrelMiles 

API and AOPL recommended 

allowing reporting for more than one 

commodity, adding columns for crude 

oil, refined products, HVL, and CO2. 

They maintained that these changes 

would return to the intent of the current 

form. 

Response 

PHMSA had revised this part of the 

form to reflect the requirement that 

operators must file separate annual 

reports for each pipeline carrying a 

different commodity type. PHMSA 

recognizes that the operator files only 

one annual report for each pipeline 

system based on the commodity 

predominantly carried. PHMSA has 

restored the option to report volume for 

all commodities, as suggested by API 

and AOPL, thus eliminating the 

possibility of double reporting mileage 

of batched systems. 

Part D—Miles of Pipe by Corrosion 

Protection and 

Part H—Miles of Pipe by Nominal Pipe 

Size 

API and AOPL suggested that we 

revise the titles of these parts to 

explicitly apply to steel pipe. 

Response 

Corrosion prevention, the subject of 

Part D, only applies to steel pipe and 

PHMSA has revised the title of this part 

accordingly. Part H applies to all pipe. 

PHMSA recognizes that most pipe in 

hazardous liquid pipeline systems is 

steel, nevertheless, there is some nonsteel pipe in some systems. PHMSA has 

not revised the title of Part H and 

expects operators to report this data for 

all pipe materials. 

Part F—Integrity Inspections Conducted 

and Actions Taken Based on Inspection 

API and AOPL suggested a number of 

changes for this part: 

• Refer to ‘‘could affect an HCA’’ vs. 

‘‘HCA affecting.’’ The former is defined 

in the regulations while the latter is not. 


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• Refer to ‘‘anomalies repaired’’ vs. 

‘‘conditions repaired’’ for consistency 

with the Plastic Pipe Data Committee 

reporting. They would have the 

instructions refer to API RP 1163 for a 

definition of ‘‘anomaly.’’ 

• Clarify that repairs are to be 

reported for the year in which the repair 

is made rather than the year in which 

an assessment was conducted. 

• Add actions (e.g., repairs) for 

ruptures that occur during pressure 

tests. 

• Add an option to question 1 for a 

combination ILI tool, since use of 

combination tools is becoming more 

prevalent. 

• Clarify that the state identifier is 

required only for intrastate pipelines. 

Response 

PHMSA agrees it is better to use terms 

defined in the regulations, and has 

revised the form to use ‘‘could affect an 

HCA’’ rather than ‘‘HCA affecting.’’ 

The regulations refer to repairs that 

must be made following IM assessments 

as ‘‘conditions’’ (i.e., immediate repair 

conditions, 60-day conditions, 180-day 

conditions). PHMSA has retained use of 

this term for those elements of questions 

in Part F that refer to repairs made that 

are required by the rule. PHMSA has 

revised the form to use the term 

‘‘anomaly’’ for those elements that refer 

to repairs made as a result of an 

operator’s criteria, which may be 

different than those in the rule. PHMSA 

has not adopted the suggestion to refer 

to API RP 1163 for the definition of 

anomaly. API RP 1163 is not currently 

incorporated by reference into the Code 

of Federal Regulations. Further, PHMSA 

considers it more important to 

understand anomalies that operators 

determine require repair. Operators may 

use the definition in API RP 1163 or 

they may use a different definition. Data 

concerning the number of repairs made 

as a result of operator-defined repair 

criteria should be reported in terms of 

the number of repairs actually made, 

regardless of a formal definition of the 

term ‘‘anomaly.’’ 

PHMSA has clarified that data to be 

reported for pressure test ruptures 

should reflect the number of repairs 

made. PHMSA has also revised the 

header for Part F to clarify that the state 

identifier is only applicable to intrastate 

pipeline systems. 

PHMSA has not modified the list of 

tool types to include a combination tool. 

PHMSA recognizes that combination 

tools are becoming more common. 

When using such a tool, an operator is 

inspecting its pipeline using each of the 

tools included in the combination, and 

the number of miles inspected should 

be reported for each of those tool types. 

Reporting the data once for a 

‘‘combination’’ tool would confuse the 

data concerning the prevalence of 

different ILI inspection methods. 

Part G—Miles of Baseline Assessments 

and Reassessments Completed (HCAAffecting Segment Miles Only) 

API and AOPL would delete this part 

because the baseline period is over for 

all pipelines and collecting assessments 

by vintage would add confusion while 

adding no useful information. They 

further commented that PHMSA should 

clarify that the state identifier is only 

required for intrastate pipelines, if 

PHMSA retains this part. 

Response 

PHMSA has not deleted this part. 

Contrary to API’s and AOPL’s assertion, 

the baseline period is not over for all 

pipelines. The baseline period is still 

running for rural low-stress pipelines 

recently made subject to Part 195, for 

example. New baseline assessments can 

also be expected as a result of new 

HCAs and new pipelines. PHMSA has 

revised this part to require data for 

baseline assessments and reassessments 

and has eliminated the need to report 

mileage by the vintage of reassessment 

(e.g., first, second). PHMSA agrees that 

this could be confusing, particularly 

when new HCAs develop near pipelines 

already assessed. PHMSA expects that 

data will show a significant drop in the 

number of conditions requiring repair as 

a result of reassessments compared to 

baseline assessments but does not 

expect the same trend between 

reassessments. 

PHMSA has clarified that the state 

identifier is only required for intrastate 

pipeline systems. 

Part J—Miles of Pipe by Specified 

Minimum Yield Strength 

API and AOPL would limit this part 

to a report of pipe above or below 20% 

SMYS because the additional categories 

are of limited use. 

Response 

PHMSA has retained the proposed 

breakdown for this part. There are few 

categories in addition to the two 

suggested by API–AOPL (i.e., above and 

below 20 percent SMYS). The limited 

additional data required addresses nonsteel pipe. Pipeline operators should 

acquire this data wherever possible. 

This data is important to pipeline 

operators so that they know where this 

pipe is and take it into account in the 

risk analyses required by IM regulations. 

PHMSA has also modified this part to 

include rural low-stress pipelines not 

generally subject to the safety 

requirements of Part 195. Section 

195.48, added by rulemaking on June 3, 

2008 (73 FR 31634), imposed the 

reporting requirements of Subpart B, 

including the requirement to submit 

annual reports, on operators of these 

pipelines. These reporting requirements 

were necessary so that PHMSA could 

collect data for the second phase of its 

rulemaking addressing rural low-stress 

pipelines. The data must be segregated 

so that it can be used for this purpose. 

The changes to Part J accommodate 

reporting by these new reporting 

operators and PHMSA’s data needs. 

Part K—Miles of Regulated Gathering 

Lines 

API and AOPL would clarify that the 

first row in this part requires reporting 

of pipelines less than ‘‘or equal to’’ 20% 

SMYS. They would also delete the row 

for non-steel pipe operating at greater 

than 125 psi, since non-steel pipe is not 

allowed in hazardous liquid pipeline 

systems. 

Response 

PHMSA agrees that the first row 

should be ‘‘less than or equal to’’ 20% 

SMYS to be consistent with the 

definition of regulated gathering lines 

and has revised the form accordingly. 

PHMSA has not deleted reference to 

non-steel pipeline operating above 125 

psi. The regulations acknowledge that 

some pipe of this type may exist within 

gathering pipeline systems (see 

195.11(a)(3)(ii)). 

Part L—HCA-Affecting Segment Miles 

of Pipe by Type of HCA 

API and AOPL recommended revising 

this part to report the total onshore and 

offshore HCA miles and not miles by 

HCA type. API and AOPL contended 

that operators do not keep data on 

mileage by HCA type given that all 

types are treated the same within an IM 

program. 

Response 

PHMSA considers that the mileage of 

pipeline that could affect HCAs of 

various types is important to its ability 

to analyze risks. PHMSA also considers 

that this data should have value for 

operators performing risk analyses 

required by IM requirements. PHMSA 

has retained this part as proposed. 

Part M—Breakout Tanks 

API and AOPL requested that we 

revise this part to allow operators to 

alternatively report information on 

breakout tanks to either to the NPMS or 

on the annual report. 


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Response 

We considered the past practice of 

allowing the option of filing breakout 

tank information via either the annual 

report or via the NPMS and determined 

that this option causes potential 

ambiguities in the data. Accordingly, we 

are eliminating the option to file this 

information via NPMS. 

Instructions 

API and AOPL noted that the 

instructions need to address electronic 

filing and the process for applying for 

alternate reporting methods. API and 

AOPL also suggested that the 

instructions refer to Appendix A of Part 

195 for examples of inter- and intra-state 

pipelines and that the definitions in the 

instructions be made consistent with 

those used for accident report forms. 

The instructions for Part G instruct 

reporting parties to compare the total 

completed and scheduled assessment 

mileage to the mileage reported in Part 

B, to identify any discrepancies, and to 

submit corrections via a supplemental 

report, as needed. API and AOPL 

contended that this could be interpreted 

to require correction of data reported in 

prior years based on current-year data. 

API and AOPL requested that PHMSA 

clarify its intent because this could 

misrepresent the IM data collected for 

prior years. 

Response 

PHMSA has revised the instructions 

to address the requirements to apply for 

non-electronic filing and to refer to 

Appendix A to Part 195 for further 

information on determining inter- and 

intrastate pipeline systems. 

PHMSA has also clarified the 

instructions for Part G to explain that 

supplemental reports should not be 

submitted for prior years based on 

current-year data. Errors in prior year 

reporting that may be identified as a 

result of collecting and reviewing data 

for a new annual report should be 

addressed by submitting a supplemental 

report for the appropriate year. 

Comments on the Safety-Related 

Condition Form 

General Comment 

NiSource suggested revising the form 

to allow for supplemental reports to 

address resolution of a condition or 

correction of previously-reported 

information. 

Part C—Condition Information 

Atmos and TPA noted that reporting 

the location of a condition by street 

address is not always appropriate and 

that other means of reporting conditions 

in rural areas should be provided. IUB 

agreed, noting that determining location 

by government land survey system (e.g., 

township, section, range) is often most 

practical in the Midwest. Spectra 

commented that a single-point location 

is often inadequate to define the 

location of a condition that extends over 

some portion of a pipeline and 

suggested defining the location as the 

center of the condition or allowing for 

designation of endpoints. 

Part D—Description of Condition 

Atmos noted that a space is needed to 

report the percent blend for biofuels, as 

specified in the instructions. NAPSR 

suggested that CO2 transported as a gas 

be added as a commodity transported in 

light of forthcoming carbon 

sequestration projects. 

Instructions 

Atmos commented that the 

instructions need to address electronic 

reporting and the requirements to apply 

for alternate reporting methods. Atmos 

and TPA also noted that the proposed 

instructions do not correlate to the 

proposed form, sections are in different 

order, and the instructions contain 

references that do not match the form. 

NAPSR requested that the instructions 

define synthetic gas. 

Response 

After considering these comments and 

evaluating its own information needs, 

PHMSA has decided to withdraw the 

proposed safety-related condition report 

and associated changes to §§ 191.25 and 

195.56. PHMSA will continue to 

evaluate its needs and may, again, 

propose changes to requirements for 

submitting safety-related condition 

reports and the information to be 

included in such reports. 

Comments on LNG Annual Report Form 

General Comments 

AGA, NiSource, INGAA, and 

Southern LNG (SLNG) commented that 

much of the data that would be reported 

on this form duplicates data currently 

submitted semi-annually to FERC, to the 

U.S. Coast Guard (USCG), or to PHMSA 

as a result of incidents. MidAmerican 

noted that terminology is inconsistent 

between this form and the LNG incident 

report form. MidAmerican also 

cautioned that ‘‘incidents’’ should not be 

referred to as ‘‘events.’’ BG&E contended 

that this information is unnecessary 

given that LNG facilities are static and 

do not expand or change over time as 

do pipelines. 

Part B—System Description 

MidAmerican questioned the 

relationship of information across a 

given row of this part. They noted that 

plants can be installed on different 

dates, in different states, and can have 

significantly different storage capacities. 

MidAmerican also noted that this part 

of the proposed form included an 

apparent formatting error in that lines 

denoting rows in the table do not extend 

across all columns. 

Part C—Releases in Past Year From 

Incidents and Safety-Related Conditions 

BG&E contended that PHMSA should 

not collect this information on annual 

reports because some of it relates to 

economic issues (e.g., insulation 

performance), rather than to safety 

issues. BG&E recommended that 

information related to incidents should 

be collected via the incident report form 

rather than annually. MidAmerican 

suggested we reformat this part because 

it is difficult to follow for operators 

trying to categorize releases by cause. 

Part D—Other Events 

AGA, NEGas and NWN recommended 

deleting this part. These commenters 

noted that other events are, by 

definition, not incidents. At most they 

are ‘‘near miss’’ events of limited 

relationship to safety and about which 

it will be difficult to collect consistent 

data. MidAmerican, NWN, and DOMAC 

cautioned that events reported on 

incident reports should not be reported 

again on this form, contending that 

summaries prepared for a different form 

at a different time are almost certain to 

result in confusion and apparent 

inconsistencies. MidAmerican, SWGas, 

and Paiute noted that this part is vague 

and needs clarification; they 

commented that several of the listed 

events appear to be subsets of 

emergency shutdown. NiSource and 

DOMAC recommended deleting 

rollovers and security breaches because 

these are not safety-significant events. 

MidAmerican maintained that both 

terms require better definition, noting 

that LNG is in constant rollover in tanks 

due to thermal gradients and suggesting 

that false activations of security 

systems/detectors should not be 

included as security breaches. 

Instructions 

TPA noted that the instructions need 

to address electronic filing and the 

requirements to apply for alternate 

reporting methods. 

Response 

Many LNG facilities under PHMSA 

jurisdiction do not fall under the 


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jurisdiction of either FERC or USCG and 

do not report to those agencies. PHMSA 

thus cannot rely on data reported to 

those agencies for a complete 

understanding of the LNG facilities for 

which it is responsible. PHMSA 

understands that LNG facilities 

experience less year-to-year change than 

do pipeline facilities and that it would 

be an unnecessary burden for LNG 

facility operators to report the same data 

on consecutive year’s forms. PHMSA 

has revised the LNG annual report form 

so that operators may report there has 

been no change from the data reported 

in the prior year. In that event, operators 

need not complete the remainder of the 

form. 

PHMSA agrees that there was a 

formatting error in Part B of the form 

that was posted in the docket for 

comment. Lines denoting rows within 

this part should have extended across 

all columns, but did not. PHMSA has 

revised the format of Part B to improve 

clarity. PHMSA considers that this 

change also resolves the apparent 

confusion about reporting of dates, 

locations, capacities, etc., as these now 

clearly relate to individual facilities. 

PHMSA has also revised the final 

form to change the formatting of Parts C 

and D. As proposed, these parts were in 

parallel columns, which appear to have 

caused confusion. In the revised form, 

these parts each extend across the entire 

form, which improves clarity. PHMSA 

does not agree that events to be reported 

in Part C (e.g., insulation performance) 

are solely economic issues with no 

safety significance. Events to be 

reported in Part C are releases of gas or 

LNG that result from these causes. 

Releases may have safety significance 

and are appropriately of interest to 

PHMSA. 

PHMSA agrees that events that have 

been reported as incidents should not be 

reported again on the annual report, and 

has revised Part D to eliminate 

categories that duplicate reportable 

incidents. PHMSA does not agree, 

however, that Part D should be deleted 

because none of the events is of safety 

significance. The remaining events do 

not reach the threshold of reporting as 

incidents or safety-related conditions, 

but do represent safety issues. They 

include, for example, situations that 

would have been reported as safetyrelated conditions had they not been 

corrected before the report of such a 

condition was required. (The safety 

significance of the conditions is the 

same as safety-related conditions. The 

only difference is time to repair). It is 

important to trend these safety events. 

Though individually of less 

significance, trends in their occurrence 

could reveal safety problems requiring 

additional regulatory attention. PHMSA 

has retained ‘‘rollover’’ as an event to be 

reported in Part D. PHMSA disagrees 

that LNG is in constant rollover. 

PHMSA agrees that blending and 

mixing routinely occur within LNG 

tanks, but this does not constitute 

rollover. Rollover is a term commonly 

understood within the LNG industry to 

refer to an event in which significant 

stratification has occurred within a tank 

and, as a result, significant quantities of 

liquefied gas suddenly relocate due to 

differences in density. Rollovers have 

resulted in damage to storage facilities 

and are safety significant events for LNG 

carriers and their unloading operations 

at import terminals. PHMSA recognizes 

that improved designs have significantly 

reduced the frequency of rollover 

occurrence, but considers events that do 

occur to be significant and to require 

reporting. PHMSA has also retained 

security breaches as an element to be 

reported in Part D. PHMSA does not 

consider it necessary to explicitly 

exclude false activations of security 

systems given that element to be 

reported is an actual breach rather than 

any activation of a security alarm 

system. 

PHMSA has revised the instructions 

to reflect the requirements to apply for 

an alternate (i.e., non-electronic) 

reporting method. 

Comments on the LNG Incident Report 

Form 

Terminology 

AGA, NWN, and NEGas noted that 

some terms used are not applicable to 

LNG operations but seem, rather, to be 

associated with pipelines (e.g., rupture 

of previously damaged pipe). 

Response 

PHMSA has revised the form and 

instructions to more accurately refer to 

LNG facilities and assure that requested 

elements are relevant to LNG. 

Part B—System Description 

DOMAC recommended that the online reporting system automatically 

populate this information with the 

operator having an opportunity to 

override or change as needed, and that 

information being collected for the OPID 

Registry should make this practical. 

BG&E commented that operational 

information is of limited relevance for 

incidents and suggested deleting this 

part. 

Response 

PHMSA is not deleting this part. 

PHMSA agrees that information in the 

OPID Registry and reported on annual 

reports should allow this part to be 

automatically populated when operators 

complete an incident report form 

electronically. We will configure the online system to do so. At the same time, 

some information may change and not 

yet have been reported to the Registry or 

NPMS. For example, the status of a 

facility may change. A mobile facility’s 

location may be different than originally 

reported. For OPIDs with multiple LNG 

facilities, the electronic system will be 

unable to identify the particular facility 

involved in the incident and will 

populate data for all facilities. The 

electronic system will thus afford 

operators the opportunity to change 

information that is automatically 

populated, including deleting 

information for facilities not involved in 

the incident. This practice will 

minimize the burden for completing this 

information, which could prove useful 

in understanding and following up on 

incidents. 

Part C—Consequences 

DOMAC suggested revising the form 

to accommodate the possible situation 

that no evacuation was necessary and 

that the area was not unsafe, in which 

case there would be no elapsed time to 

make the area safe. 

Response 

PHMSA has revised the form to 

replace the question concerning elapsed 

time until the area was made safe to one 

asking for a timeline of the incident. 

This avoids the implication that the 

situation was ‘‘unsafe.’’ PHMSA has 

retained reporting for evacuations. We 

have revised the instructions to require 

that operators complete this information 

based on their own knowledge or based 

on reports by police, fire or other 

emergency responder. If no evacuation 

was needed, operators enter zero. If an 

estimate is not possible, operators are 

requested to describe why in the 

narrative portion of the form. 

Evacuation information is collected in 

this same manner for pipeline incidents. 

Part D—Origin of Gas Leak/Problem 

DOMAC suggested that ‘‘gas leak’’ be 

replaced with ‘‘release,’’ noting that a 

release may have been in liquid form. 

BG&E recommended deleting questions 

related to distributed control systems 

(DCS), since such systems are not 

required, the information is of limited 

value, and it will be burdensome to 

collect. DOMAC agreed that information 

concerning DCS systems would be of 

limited value, noting that such systems 

do not detect all hazards (e.g., fire). 

TPA commented that the list in 

question 1 of gases potentially involved 


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is unnecessary given that the form is 

intended for LNG facilities only. 

DOMAC suggested revising the title of 

question 2 in this part from ‘‘leak 

detection’’ to ‘‘hazard detection.’’ 

DOMAC also suggested reorganizing the 

form to place this part before Part C; 

since an incident begins with a release 

it would be logical to begin data 

collection with the origin of the release 

rather than its consequences. 

Response 

PHMSA does not agree that references 

to DCS should be deleted. PHMSA has 

revised this part to address 

‘‘computerized control systems,’’ 

encompassing computer-based control 

systems that may be referred to by terms 

other than DCS. PHMSA recognizes that 

computerized control systems are not 

required to be installed in LNG 

facilities, but also notes that many 

facilities use such systems. It is 

important for PHMSA to understand 

how useful these systems are in 

identifying incidents. The information 

required for computerized control 

systems is very limited—whether one 

was in place and whether it initially 

detected the event—and thus not 

burdensome to report. 

PHMSA has retained the list of gases 

in question D1. The list simply asks 

whether the incident originated with 

natural gas, LNG or ‘‘other flammable 

gas.’’ Other gases are used in 

liquefaction processes and could be the 

origin of events that escalate to 

incidents. The definition of an incident 

in § 191.3 refers to events resulting in 

reportable consequences due to a release 

of ‘‘refrigerant gas,’’ which may include 

other flammable gases. 

PHMSA has not re-ordered the form 

to put Part D before Part C. While it is 

true that most incidents involve a 

release, the definition also includes 

emergency shutdowns and events that 

the operator considers significant even 

though they do not meet the other 

specified criteria. These other 

significant events may not involve a 

release (e.g., security breach). Part C 

reports consequences, which is why the 

event constituted an incident in the first 

place. PHMSA considers that the order 

of these sections is appropriate. 

Part E—Suspected Causes 

DOMAC commented that this part 

appears to be taken from a pipeline 

context and does not fit the LNG 

environment. 

Response 

We have revised this part to be more 

applicable to the LNG environment. 

Instructions 

DOMAC noted that the instructions 

refer to Part 192 vs. Part 193 and will 

require significant revision. TPA 

suggested that the instructions for Part 

D, question 2, refer to ‘‘how was the 

release detected’’ instead of ‘‘where the 

leak/problem occurred.’’ TPA also noted 

that the instructions need to address the 

requirements for reporting by methods 

other than electronic reporting. 

Response 

PHMSA has revised the instructions 

to be consistent with the form as 

modified. The instructions include an 

explanation of how an operator must 

apply to use alternate reporting 

methods. PHMSA notes its strong 

preference for electronic reporting, 

which will be the required method for 

all reports addressed in this rule. 

Allowance is made for alternative 

methods when operators demonstrate 

that electronic reporting involves undue 

burden. PHMSA will review requests for 

use of alternate methods critically to 

assure that electronic reporting would 

be truly burdensome before approving 

an alternative. 

Comments on Offshore Pipeline 

Condition Report Form 

API and AOPL noted that the form 

does not accommodate the likelihood 

that inspections will be completed with 

no exposed pipe identified. 

Response 

As discussed above, PHMSA is 

withdrawing this proposed form. 

V. Advisory Committee 

Recommendations 

The Technical Pipeline Safety 

Standards Committee (TPSSC) and the 

Technical Hazardous Liquid Pipeline 

Safety Standards Committee (THLPSSC) 

considered the July 2, 2009, NPRM to 

revise the reporting requirements in the 

pipeline safety regulations at a joint 

meeting on December 9, 2009. A 

transcript of this meeting is available in 

the docket. 

The TPSSC and THLPSSC have been 

established by statute to evaluate 

proposed pipeline safety regulations. 

Each committee has an authorized 

membership of 15 individuals with 

membership evenly divided between 

the government, industry, and the 

public. Each member of these 

committees is qualified to consider the 

technical feasibility, reasonableness, 

cost-effectiveness, and practicability of 

proposed pipeline safety regulations. 

Each committee voted to support the 

proposed rule, subject to comments 

made during committee discussion. The 

amendments adopted in this final rule 

are consistent with the 

recommendations of the committees 

except for the issue of the change in the 

definition of an incident and the volume 

of measure for release of gas. The 

committees recommended that PHMSA 

adopt a threshold of 10,000 Mcf and not 

the 3,000 Mcf threshold proposed in the 

NPRM. For the reasons stated in Section 

2, ‘‘Changing the definition of an 

‘Incident’ for gas pipelines’’ of the 

preamble, PHMSA has adopted a 

threshold of 3,000 Mcf. Committee 

comments generally were consistent 

with written comments filed by other 

commenters discussed above. 

VI. Section-by-Section Analysis 

1. Section 191.1—This Section is 

amended to include in the scope of Part 

191 regulated rural gathering lines. 

Rural onshore regulated gathering lines 

were defined by a final rule published 

March 15, 2006 (71 FR 13289), but that 

rule unintentionally failed to include 

these newly regulated lines in the 

reporting requirements of Part 191. 

2. Section 191.3—This Section is 

amended to revise the definition of an 

incident for gas pipelines and LNG 

facilities. As discussed elsewhere in this 

document, principal changes include 

the addition of a criterion defining as an 

incident an unintentional release of gas 

that results in estimated gas loss of 3 

million cubic feet or more. The criterion 

defining an incident on the basis of 

$50,000 property damage is 

correspondingly revised to omit 

consideration of the cost of gas lost. 

This amendment also clarifies that the 

activation of an emergency shutdown 

system at an LNG facility for reasons 

other than an actual emergency does not 

constitute an incident. 

3. Sections 191.7 and 195.58—These 

Sections are amended to require that all 

required reports, except safety-related 

condition reports and offshore condition 

reports, be submitted electronically 

unless an operator has demonstrated 

that electronic reporting would pose an 

undue burden and hardship and has 

obtained PHMSA approval to report by 

other means. 

4. Section 191.9—This Section is 

amended to remove the exclusion for 

LNG facilities that are part of 

distribution pipeline systems. 

Submission of incident reports for these 

facilities will now be required. 

5. Section 191.11—This Section is 

amended to remove the exclusion for 

LNG facilities. Submission of annual 

reports for these facilities will now be 

required. 

6. Section 191.15—This Section is 

amended to add the requirement that 


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operators of LNG facilities submit 

written incident reports. 

7. Section 191.17—This Section is 

amended to add the requirement that 

operators of LNG facilities submit 

annual reports. 

8. Sections 191.19 and 195.62—These 

Sections described how to obtain copies 

of required forms. The Sections are 

being removed, because all reports for 

which forms have been approved will 

now be required to be made 

electronically. Copies of the forms on 

which the electronic reporting system is 

based will continue to be available on 

PHMSA’s Web site. 

9. Sections 191.21 and 195.63—These 

Sections are amended to include new 

forms that are included under OMB 

Control Number 2137–0522 for gas 

pipelines and to add new OMB control 

numbers for forms associated with 

hazardous liquid pipelines. 

10. Sections 191.22 and 195.64— 

These Sections are added to create a 

National Registry of Pipeline and LNG 

Operators. Operators will use the 

Registry to obtain and change an OPID. 

Operators who already have one or more 

OPIDs are required to validate the 

information in PHMSA’s records 

currently associated with those OPIDs 

within six months. Operators are 

required to notify PHMSA, via the 

Registry, of certain changes that affect 

the facilities associated with an OPID. 

Operators are also required to use their 

assigned OPID for all reporting 

requirements and for submissions to the 

NPMS. Operators are also required to 

notify PHMSA of changes within safety 

programs managed in common across 

multiple OPIDs (e.g., where a company 

operates multiple pipelines) that affect 

the OPID the operator considers 

‘‘primary’’ for that program (generally 

representing which operating entity is 

responsible for the program). 

PHMSA has previously obtained this 

information from operators informally, 

usually from an operator’s compliance 

personnel, as this information is needed 

for inspection planning. PHMSA will 

also use this information to analyze 

safety program performance and to 

identify trends. 

11. Section 192.945—This Section is 

amended to reflect the integration of 

reporting of IM performance measures 

for gas transmission pipelines into the 

annual report. Semi-annual reporting of 

IM performance measures is no longer 

required. 

12. Section 192.951—This Section is 

amended to require that all reports 

required by Subpart O of Part 192 be 

submitted electronically in accordance 

with revised § 191.7. 

13. Section 193.2011—This Section is 

amended to require that LNG facility 

operators submit annual reports and 

reports of incidents and safety-related 

conditions in accordance with the 

requirements of Part 191. 

15. Section 195.48—This Section 

specifies the scope of hazardous liquid 

pipelines subject to the reporting 

requirements of Subpart B of Part 195. 

Exceptions from portions of the annual 

report for pipelines not otherwise 

subject to Part 195 have been revised 

and moved to § 195.49. 

15. Section 195.49—This Section is 

amended to require that some parts of 

the hazardous liquid pipeline annual 

report form (designated on the form) 

must be completed separately for each 

state a pipeline traverses. 

16. Section 195.52—This Section is 

amended to require that hazardous 

liquid pipeline operators have a written 

procedure for calculating an initial 

estimate of the amount of product 

released in an accident. The amended 

Section also requires that operators 

provide an additional telephonic report 

if significant new information becomes 

available during the emergency 

response phase. 

17. Section 195.54—This Section is 

revised to remove the option to submit 

a facsimile of the PHMSA form because 

all reports must now be submitted 

electronically. 

VII. Regulatory Analyses and Notices 

This final rule is published under the 

authority of the Federal Pipeline Safety 

Law (49 U.S.C. 60101 et seq.). Section 

60102 authorizes the Secretary of 

Transportation to issue regulations 

governing design, installation, 

inspection, emergency plans and 

procedures, testing, construction, 

extension, operation, replacement, and 

maintenance of pipeline facilities. The 

amendments to the data collections 

requirements of the Pipeline Safety 

Regulations addressed in this 

rulemaking are issued under this 

authority and address NTSB and GAO 

recommendations. This rulemaking also 

carries out the mandates regarding 

incident reporting requirements under 

section 15 of the Pipeline Inspection, 

Protection, Enforcement, and Safety Act 

of 2006 (Pub. L. No. 109–468, Dec. 29, 

2006). 

Executive Order 12866 and DOT 

Policies and Procedures 

This final rule is not a significant 

regulatory action under section 3(f) of 

Executive Order 12866 (58 FR 51735) 

and, therefore, was not reviewed by the 

OMB. This final rule is not significant 

under the Regulatory Policies and 

Procedures of the Department of 

Transportation (44 FR 11034). 

Overall, the costs of the final rule are 

approximately $1.6 million per year. 

The present value of this cost over ten 

years at a seven percent discount rate is 

approximately $11 million. Those costs 

cover changes to the 49 CFR to enhance 

general data and data management 

improvements for pipelines. 

The average of the present value of 

net benefits over ten years at a seven 

percent discount rate is approximately 

$73 million. 

The benefits of the final rule enhance 

PHMSA’s ability to understand, 

measure, and assess the performance of 

individual operators and industry as a 

whole; integrate pipeline safety data in 

a way that will allow a more thorough, 

rigorous, and comprehensive 

understanding and assessment of risk; 

expand and simplify existing electronic 

reporting by operators; improve the data 

and analyses PHMSA relies on to make 

critical, safety-related decisions; and 

facilitate PHMSA’s allocation of 

inspection and other resources based on 

a more accurate accounting of risk. 

A comparison of the benefits and 

costs of the rule results in positive net 

benefits. The present value of net 

benefits (the excess of benefits over 

costs) for the final rule is approximately 

$73 million using a seven percent 

discount rate. A copy of the regulatory 

evaluation is available for review in the 

docket. 

Regulatory Flexibility Act 

The Regulatory Flexibility Act of 

1980, as amended, requires Federal 

agencies to conduct a separate analysis 

of the economic impact of rules on 

small entities. The Regulatory 

Flexibility Act requires that Federal 

agencies take small entities’ concerns 

into account when developing, writing, 

publicizing, promulgating, and 

enforcing regulations. The requirements 

imposed in this final rule will affect 

hazardous liquid, natural gas pipelines 

(distribution and transmission), and 

LNG facility operators. 

The Small Business Administration 

(SBA) size standards for hazardous 

liquid operators are companies with less 

than 1,500 employees, including 

employees of parent corporations. The 

SBA size standards are $6.5 million in 

annual revenues for the natural gas 

transmission pipeline industry and 500 

employees for the natural gas 

distribution industry. PHMSA has 

reviewed the data it collects from the 

hazardous liquid pipeline industry and 

has estimated there are approximately 

220 small hazardous liquid pipeline 

operators, 475 natural gas transmission 


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pipeline operators, and 54 LNG facility 

operators that may be considered small 

entities. The rule could result in a 

significant adverse economic impact on 

small entities if the estimated average 

annual costs attributed to the rule 

exceed one percent of their annual 

revenues. Since the average cost of the 

rule for each small pipeline operator 

affected by the rule is modest— 

estimated at $6,691 for each hazardous 

liquid pipeline operator, $461 for each 

natural gas transmission operator and 

$913 for each LNG facility operator— 

PHMSA concludes that there will not be 

a significant impact on a substantial 

number of small pipeline operators. 

Executive Order 13175 

PHMSA has analyzed this final rule 

according to the principles and criteria 

in Executive Order 13175, ‘‘Consultation 

and Coordination with Indian Tribal 

Governments.’’ Because this final rule 

does not significantly or uniquely affect 

the communities of the Indian tribal 

governments or impose substantial 

direct compliance costs, the funding 

and consultation requirements of 

Executive Order 13175 do not apply. 

Paperwork Reduction Act 

This final rule has resulted in 

revisions to several information 

collections that have either been 

approved by OMB, or have been 

submitted to OMB for approval. The 

following list contains the approved 

information collection and its approval 

information: 

OMB Control 

No. Info collection title Expiration date Approved burden hours 

1 ....................................... 2137–0522 Incident and Annual Reports for Gas Pipeline Operators ............ 11/30/2011 53,627 

The following list contains the 

information collections that have been 

submitted to OMB for approval. When 

approval is received from OMB on these 

information collections, PHMSA will 

publish a notice announcing their 

approval in the Federal Register: 

OMB Control 

No. Info collection title 

1 ............... 2137–0047 Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting 

2 ............... 2137–0614 Pipeline Safety: New Reporting Requirements for Hazardous Liquid Pipeline Operators; Hazardous Liquid Annual 

Report. 

Unfunded Mandates Reform Act of 1995 

This final rule does not impose 

unfunded mandates under the 

Unfunded Mandates Reform Act of 

1995. It would not result in costs of 

$100 million, adjusted for inflation, or 

more in any one year to either State, 

local, or tribal governments, in the 

aggregate, or to the private sector, and 

is the least burdensome alternative that 

achieves the objective of the final rule. 

National Environmental Policy Act 

PHMSA analyzed the proposed rule 

in accordance with section 102(2)(c) of 

the National Environmental Policy Act 

(42 U.S.C. 4332), the Council on 

Environmental Quality regulations (40 

CFR 1500–1508), and DOT Order 

5610.1C, and preliminarily determined 

the action would not significantly affect 

the quality of the human environment. 

We received no comment on this 

determination. Therefore, we conclude 

that this action will not significantly 

affect the quality of the human 

environment. 

Executive Order 13132 

PHMSA has analyzed this final rule 

according to Executive Order 13132 

(‘‘Federalism’’). The final rule does not 

have a substantial direct effect on the 

States, the relationship between the 

national government and the States, or 

the distribution of power and 

responsibilities among the various 

levels of government. This final rule 

does not impose substantial direct 

compliance costs on State and local 

governments. This final rule does not 

preempt state law for intrastate 

pipelines. Therefore, the consultation 

and funding requirements of Executive 

Order 13132 do not apply. 

Executive Order 13211 

This final rule is not a ‘‘significant 

energy action’’ under Executive Order 

13211 (Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use). It is not likely to 

have a significant adverse effect on 

supply, distribution, or energy use. 

Further, the Office of Information and 

Regulatory Affairs has not designated 

this final rule as a significant energy 

action. 

Privacy Act Statement 

Anyone may search the electronic 

form of all comments received for any 

of our dockets. You may review DOT’s 

complete Privacy Act Statement in the 

Federal Register published on April 11, 

2000 (70 FR 19477) or visit http:// 

dms.dot.gov. 

List of Subjects 

49 CFR Part 191 

Pipeline Safety, Reporting and 

recordkeeping requirements. 

49 CFR Part 192 

Pipeline safety, Fire prevention, 

Security measures. 

49 CFR Part 193 

Pipeline safety, Fire prevention, 

Security measures, and Reporting and 

recordkeeping requirements. 

49 CFR Part 195 

Ammonia, Carbon dioxide, 

Incorporation by reference, Petroleum, 

Pipeline safety, Reporting and 

recordkeeping requirements. 

■ In consideration of the foregoing, 49 

CFR Chapter I is amended as follows: 

PART 191—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE; ANNUAL REPORTS, 

INCIDENT REPORTS, AND SAFETY– 

RELATED CONDITION REPORTS 

■ 1. The authority citation for Part 191 

continues to read as follows: 

Authority: 49 U.S.C. 5121, 60102, 60103, 

60104, 60108, 60117, 60118, and 60124, and 

49 CFR 1.53. 

■ 2. In § 191.1, paragraph (b)(4) is 

revised to read as follows: 

§ 191.1 Scope. 

* * * * * 

(b) * * * 

(4) Onshore gathering of gas— 


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(i) Through a pipeline that operates at 

less than 0 psig (0 kPa); 

(ii) Through a pipeline that is not a 

regulated onshore gathering line (as 

determined in § 192.8 of this 

subchapter); and 

(iii) Within inlets of the Gulf of 

Mexico, except for the requirements in 

§ 192.612. 

■ 3. In § 191.3, the definition of 

‘‘Incident’’ is revised to read as follows: 

§ 191.3 Definitions. 

* * * * * 

Incident means any of the following 

events: 

(1) An event that involves a release of 

gas from a pipeline, or of liquefied 

natural gas, liquefied petroleum gas, 

refrigerant gas, or gas from an LNG 

facility, and that results in one or more 

of the following consequences: 

(i) A death, or personal injury 

necessitating in-patient hospitalization; 

(ii) Estimated property damage of 

$50,000 or more, including loss to the 

operator and others, or both, but 

excluding cost of gas lost; 

(iii) Unintentional estimated gas loss 

of three million cubic feet or more; 

(2) An event that results in an 

emergency shutdown of an LNG facility. 

Activation of an emergency shutdown 

system for reasons other than an actual 

emergency does not constitute an 

incident. 

(3) An event that is significant in the 

judgment of the operator, even though it 

did not meet the criteria of paragraphs 

(1) or (2) of this definition. 

* * * * * 

■ 4. In § 191.5, the section heading and 

paragraph (b) introductory text are 

revised to read as follows: 

§ 191.5 Immediate notice of certain 

incidents. 

* * * * * 

(b) Each notice required by paragraph 

(a) of this section must be made to the 

National Response Center either by 

telephone to 800–424–8802 (in 

Washington, DC, 202 267–2675) or 

electronically at http:// 

www.nrc.uscg.mil and must include the 

following information: 

* * * * * 

■ 5. Section 191.7 is revised to read as 

follows: 

§ 191.7 Report submission requirements. 

(a) General. Except as provided in 

paragraph (b) of this section, an operator 

must submit each report required by 

this part electronically to the Pipeline 

and Hazardous Materials Safety 

Administration at http:// 

opsweb.phmsa.dot.gov unless an 

alternative reporting method is 

authorized in accordance with 

paragraph (d) of this section. 

(b) Exceptions. An operator is not 

required to submit a safety-related 

condition report (§ 191.25) or an 

offshore pipeline condition report 

(§ 191.27) electronically. 

(c) Safety-related conditions. An 

operator must submit concurrently to 

the applicable State agency a safetyrelated condition report required by 

§ 191.23 for intrastate pipeline 

transportation or when the State agency 

acts as an agent of the Secretary with 

respect to interstate transmission 

facilities. 

(d) Alternative Reporting Method. If 

electronic reporting imposes an undue 

burden and hardship, an operator may 

submit a written request for an 

alternative reporting method to the 

Information Resources Manager, Office 

of Pipeline Safety, Pipeline and 

Hazardous Materials Safety 

Administration, PHP–20, 1200 New 

Jersey Avenue, SE, Washington DC 

20590. The request must describe the 

undue burden and hardship. PHMSA 

will review the request and may 

authorize, in writing, an alternative 

reporting method. An authorization will 

state the period for which it is valid, 

which may be indefinite. An operator 

must contact PHMSA at 202–366–8075, 

or electronically to 

informationresourcesmanager@dot.gov 

or make arrangements for submitting a 

report that is due after a request for 

alternative reporting is submitted but 

before an authorization or denial is 

received. 

■ 6. In § 191.9, paragraph (c) is revised 

to read as follows: 

§ 191.9 Distribution system: Incident 

report. 

* * * * * 

(c) Master meter operators are not 

required to submit an incident report as 

required by this section. 

■ 7. Section 191.11 is revised to read as 

follows: 

§ 191.11 Distribution system: Annual 

report. 

(a) General. Except as provided in 

paragraph (b) of this section, each 

operator of a distribution pipeline 

system must submit an annual report for 

that system on DOT Form PHMSA F 

7100.1–1. This report must be submitted 

each year, not later than March 15, for 

the preceding calendar year. 

(b) Not required. The annual report 

requirement in this section does not 

apply to a master meter system or to a 

petroleum gas system that serves fewer 

than 100 customers from a single 

source. 

■ 8. Section 191.15 is revised to read as 

follows: 

§ 191.15 Transmission systems; gathering 

systems; and liquefied natural gas facilities: 

Incident report. 

(a) Transmission or Gathering. Each 

operator of a transmission or a gathering 

pipeline system must submit DOT Form 

PHMSA F 7100.2 as soon as practicable 

but not more than 30 days after 

detection of an incident required to be 

reported under § 191.5 of this part. 

(b) LNG. Each operator of a liquefied 

natural gas plant or facility must submit 

DOT Form PHMSA F 7100.3 as soon as 

practicable but not more than 30 days 

after detection of an incident required to 

be reported under § 191.5 of this part. 

(c) Supplemental report. Where 

additional related information is 

obtained after a report is submitted 

under paragraph (a) or (b) of this 

section, the operator must make a 

supplemental report as soon as 

practicable with a clear reference by 

date to the original report. 

■ 9. Section 191.17 is revised to read as 

follows: 

§ 191.17 Transmission systems; gathering 

systems; and liquefied natural gas facilities: 

Annual report. 

(a) Transmission or Gathering. Each 

operator of a transmission or a gathering 

pipeline system must submit an annual 

report for that system on DOT Form 

PHMSA 7100.2.1. This report must be 

submitted each year, not later than 

March 15, for the preceding calendar 

year, except that for the 2010 reporting 

year the report must be submitted by 

June 15, 2011. 

(b) LNG. Each operator of a liquefied 

natural gas facility must submit an 

annual report for that system on DOT 

Form PHMSA 7100.3–1 This report 

must be submitted each year, not later 

than March 15, for the preceding 

calendar year, except that for the 2010 

reporting year the report must be 

submitted by June 15, 2011. 

§ 191.19 [Removed] 

■ 10. Section 191.19 is removed. 

■ 11. Section 191.21 is revised to read 

as follows: 

§ 191.21 OMB control number assigned to 

information collection. 

This section displays the control 

number assigned by the Office of 

Management and Budget (OMB) to the 

information collection requirements in 

this part. The Paperwork Reduction Act 

requires agencies to display a current 

control number assigned by the Director 


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of OMB for each agency information 

collection requirement. 

OMB CONTROL NUMBER 2137–0522 

Section of 49 CFR Part 191 where identified Form No. 

191.5 ............................................................................................................................................................................... Telephonic. 

191.9 ............................................................................................................................................................................... PHMSA 7100.1, PHMSA 

7100.3. 

191.11 ............................................................................................................................................................................. PHMSA 7100.1–1, PHMSA 

7100.3–1. 

191.15 ............................................................................................................................................................................. PHMSA 7100.2. 

191.17 ............................................................................................................................................................................. PHMSA 7100.2–1. 

191.22 ............................................................................................................................................................................. PHMSA 1000.1. 

■ 12. Section 191.22 is added to read as 

follows: 

§ 191.22 National Registry of Pipeline and 

LNG Operators. 

(a) OPID Request. Effective January 1, 

2012, each operator of a gas pipeline, 

gas pipeline facility, LNG plant or LNG 

facility must obtain from PHMSA an 

Operator Identification Number (OPID). 

An OPID is assigned to an operator for 

the pipeline or pipeline system for 

which the operator has primary 

responsibility. To obtain on OPID, an 

operator must complete an OPID 

Assignment Request DOT Form PHMSA 

F 1000.1 through the National Registry 

of Pipeline and LNG Operators in 

accordance with § 191.7. 

(b) OPID validation. An operator who 

has already been assigned one or more 

OPID by January 1, 2011, must validate 

the information associated with each 

OPID through the National Registry of 

Pipeline and LNG Operators at http:// 

opsweb.phmsa.dot.gov, and correct that 

information as necessary, no later than 

June 30, 2012. 

(c) Changes. Each operator of a gas 

pipeline, gas pipeline facility, LNG 

plant or LNG facility must notify 

PHMSA electronically through the 

National Registry of Pipeline and LNG 

Operators at http:// 

opsweb.phmsa.dot.gov of certain events. 

(1) An operator must notify PHMSA 

of any of the following events not later 

than 60 days before the event occurs: 

(i) Construction or any planned 

rehabilitation, replacement, 

modification, upgrade, uprate, or update 

of a facility, other than a section of line 

pipe, that costs $10 million or more. If 

60 day notice is not feasible because of 

an emergency, an operator must notify 

PHMSA as soon as practicable; 

(ii) Construction of 10 or more miles 

of a new pipeline; or 

(iii) Construction of a new LNG plant 

or LNG facility. 

(2) An operator must notify PHMSA 

of any of the following events not later 

than 60 days after the event occurs: 

(i) A change in the primary entity 

responsible (i.e., with an assigned OPID) 

for managing or administering a safety 

program required by this part covering 

pipeline facilities operated under 

multiple OPIDs. 

(ii) A change in the name of the 

operator; 

(iii) A change in the entity (e.g., 

company, municipality) responsible for 

an existing pipeline, pipeline segment, 

pipeline facility, or LNG facility; 

(iv) The acquisition or divestiture of 

50 or more miles of a pipeline or 

pipeline system subject to Part 192 of 

this subchapter; or 

(v) The acquisition or divestiture of an 

existing LNG plant or LNG facility 

subject to Part 193 of this subchapter. 

(d) Reporting. An operator must use 

the OPID issued by PHMSA for all 

reporting requirements covered under 

this subchapter and for submissions to 

the National Pipeline Mapping System. 

PART 192—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

■ 13. The authority citation for Part 192 

continues to read as follows: 

Authority: 49 U.S.C. 5103, 60102, 60104, 

60108, 60109, 60110, 60113, and 60118; and 

49 CFR 1.53. 

■ 14. In § 192.945, paragraph (a) is 

revised to read as follows: 

§ 192.945 What methods must an operator 

use to measure program effectiveness? 

(a) General. An operator must include 

in its integrity management program 

methods to measure whether the 

program is effective in assessing and 

evaluating the integrity of each covered 

pipeline segment and in protecting the 

high consequence areas. These measures 

must include the four overall 

performance measures specified in 

ASME/ANSI B31.8S (incorporated by 

reference, see § 192.7 of this part), 

section 9.4, and the specific measures 

for each identified threat specified in 

ASME/ANSI B31.8S, Appendix A. An 

operator must submit the four overall 

performance measures as part of the 

annual report required by § 191.17 of 

this subchapter. 

■ 15. Section 192.951 is revised to read 

as follows: 

* * * * * 

§ 192.951 Where does an operator file a 

report? 

An operator must file any report 

required by this subpart electronically 

to the Pipeline and Hazardous Materials 

Safety Administration in accordance 

with § 191.7 of this subchapter. 

PART 193—LIQUEFIED NATURAL GAS 

FACILITIES: FEDERAL SAFETY 

STANDARDS 

■ 16. The authority citation for Part 193 

continues to read as follows: 

Authority: 49 U.S.C. 5103, 60102, 60103, 

60104, 60108, 60109, 60110, 60113, 60118, 

and 49 CFR 1.53. 

■ 17. Section 193.2011 is revised to read 

as follows: 

§ 193.2011 Reporting. 

Incidents, safety-related conditions, 

and annual pipeline summary data for 

LNG plants or facilities must be 

reported in accordance with the 

requirements of Part 191 of this 

subchapter. 

PART 195—TRANSPORTATION OF 

HAZARDOUS LIQUIDS BY PIPELINE 

■ 18. The authority citation for Part 195 

continues to read as follows: 

Authority: 49 U.S.C. 5103, 60102, 60104, 

60108, 60109, 60118, and 49 CFR 1.53. 

■ 19. Section 195.48 is revised to read 

as follows: 

§ 195.48 Scope. 

This subpart prescribes requirements 

for periodic reporting and for reporting 

of accidents and safety-related 

conditions. This subpart applies to all 


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pipelines subject to this part and, 

beginning January 5, 2009, applies to all 

rural low-stress hazardous liquid 

pipelines. 

■ 20. Section 195.49 is revised to read 

as follows: 

§ 195.49 Annual report. 

Each operator must annually 

complete and submit DOT Form 

PHMSA F 7000–1.1 for each type of 

hazardous liquid pipeline facility 

operated at the end of the previous year. 

An operator must submit the annual 

report by June 15 each year, except that 

for the 2010 reporting year the report 

must be submitted by August 15, 2011. 

A separate report is required for crude 

oil, HVL (including anhydrous 

ammonia), petroleum products, carbon 

dioxide pipelines, and fuel grade 

ethanol pipelines. For each state a 

pipeline traverses, an operator must 

separately complete those sections on 

the form requiring information to be 

reported for each state. 

■ 21. Section 195.52 is revised to read 

as follows: 

§ 195.52 Immediate notice of certain 

accidents. 

(a) Notice requirements. At the 

earliest practicable moment following 

discovery of a release of the hazardous 

liquid or carbon dioxide transported 

resulting in an event described in 

§ 195.50, the operator of the system 

must give notice, in accordance with 

paragraph (b) of this section, of any 

failure that: 

(1) Caused a death or a personal 

injury requiring hospitalization; 

(2) Resulted in either a fire or 

explosion not intentionally set by the 

operator; 

(3) Caused estimated property 

damage, including cost of cleanup and 

recovery, value of lost product, and 

damage to the property of the operator 

or others, or both, exceeding $50,000; 

(4) Resulted in pollution of any 

stream, river, lake, reservoir, or other 

similar body of water that violated 

applicable water quality standards, 

caused a discoloration of the surface of 

the water or adjoining shoreline, or 

deposited a sludge or emulsion beneath 

the surface of the water or upon 

adjoining shorelines; or 

(5) In the judgment of the operator 

was significant even though it did not 

meet the criteria of any other paragraph 

of this section. 

(b) Information required. Each notice 

required by paragraph (a) of this section 

must be made to the National Response 

Center either by telephone to 800–424– 

8802 (in Washington, DC, 202–267– 

2675) or electronically at http:// 

www.nrc.uscg.mil and must include the 

following information: 

(1) Name, address and identification 

number of the operator. 

(2) Name and telephone number of 

the reporter. 

(3) The location of the failure. 

(4) The time of the failure. 

(5) The fatalities and personal 

injuries, if any. 

(6) Initial estimate of amount of 

product released in accordance with 

paragraph (c) of this section. 

(7) All other significant facts known 

by the operator that are relevant to the 

cause of the failure or extent of the 

damages. 

(c) Calculation. A pipeline operator 

must have a written procedure to 

calculate and provide a reasonable 

initial estimate of the amount of 

released product. 

(d) New information. An operator 

must provide an additional telephonic 

report to the NRC if significant new 

information becomes available during 

the emergency response phase of a 

reported event at the earliest practicable 

moment after such additional 

information becomes known. 

■ 22. In § 195.54, paragraph (a) is 

revised to read as follows: 

§ 195.54 Accident reports. 

(a) Each operator that experiences an 

accident that is required to be reported 

under § 195.50 must, as soon as 

practicable, but not later than 30 days 

after discovery of the accident, file an 

accident report on DOT Form 7000–1. 

* * * * * 

■ 23. Section 195.58 is revised to read 

as follows: 

§ 195.58 Report submission requirements. 

(a) General. Except as provided in 

paragraph (b) of this section, an operator 

must submit each report required by 

this part electronically to PHMSA at 

http://opsweb.phmsa.dot.gov unless an 

alternative reporting method is 

authorized in accordance with 

paragraph (d) of this section. 

(b) Exceptions. An operator is not 

required to submit a safety-related 

condition report (§ 195.56) or an 

offshore pipeline condition report 

(§ 195.67) electronically. 

(c) Safety-related conditions. An 

operator must submit concurrently to 

the applicable State agency a safetyrelated condition report required by 

§ 195.55 for an intrastate pipeline or 

when the State agency acts as an agent 

of the Secretary with respect to 

interstate pipelines. 

(d) Alternate Reporting Method. If 

electronic reporting imposes an undue 

burden and hardship, the operator may 

submit a written request for an 

alternative reporting method to the 

Information Resources Manager, Office 

of Pipeline Safety, Pipeline and 

Hazardous Materials Safety 

Administration, PHP–20, 1200 New 

Jersey Avenue, SE., Washington DC 

20590. The request must describe the 

undue burden and hardship. PHMSA 

will review the request and may 

authorize, in writing, an alternative 

reporting method. An authorization will 

state the period for which it is valid, 

which may be indefinite. An operator 

must contact PHMSA at 202–366–8075, 

or electronically to ‘‘information

resourcesmanager@dot.gov’’ to make 

arrangements for submitting a report 

that is due after a request for alternative 

reporting is submitted but before an 

authorization or denial is received. 

§ 195.62 [Removed] 

■ 24. Section 195.62 is removed. 

■ 25. Section 195.63 is revised to read 

as follows: 

§ 195.63 OMB control number 

assigned to information collection. 

The control numbers assigned by the 

Office of Management and Budget to the 

hazardous liquid pipeline information 

collection pursuant to the Paperwork 

Reduction Act are 2137–0047, 2137– 

0601, 2137–0604, 2137–0605, 2137– 

0618, and 2137–0622. 

■ 26. Section 195.64 is added to read as 

follows: 

§ 195.64 National Registry of Pipeline and 

LNG Operators. 

(a) OPID Request. Effective January 1, 

2012, each operator of a hazardous 

liquid pipeline or pipeline facility must 

obtain from PHMSA an Operator 

Identification Number (OPID). An OPID 

is assigned to an operator for the 

pipeline or pipeline system for which 

the operator has primary responsibility. 

To obtain an OPID or a change to an 

OPID, an operator must complete an 

OPID Assignment Request DOT Form 

PHMSA F 1000.1 through the National 

Registry of Pipeline and LNG Operators 

in accordance with § 195.58. 

(b) OPID validation. An operator who 

has already been assigned one or more 

OPID by January 1, 2011 must validate 

the information associated with each 

such OPID through the National 

Registry of Pipeline and LNG Operators 

at http://opsweb.phmsa.dot.gov, and 

correct that information as necessary, no 

later than June 30, 2012. 

(c) Changes. Each operator must 

notify PHMSA electronically through 

the National Registry of Pipeline and 

LNG Operators at http:// 


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72908 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

opsweb.phmsa.dot.gov, of certain 

events. 

(1) An operator must notify PHMSA 

of any of the following events not later 

than 60 days before the event occurs: 

(i) Construction or any planned 

rehabilitation, replacement, 

modification, upgrade, uprate, or update 

of a facility, other than a section of line 

pipe, that costs $10 million or more. If 

60 day notice is not feasible because of 

an emergency, an operator must notify 

PHMSA as soon as practicable; 

(ii) Construction of 10 or more miles 

of a new hazardous liquid pipeline; or 

(iii) Construction of a new pipeline 

facility. 

(2) An operator must notify PHMSA 

of any following event not later than 60 

days after the event occurs: 

(i) A change in the primary entity 

responsible (i.e., with an assigned OPID) 

for managing or administering a safety 

program required by this part covering 

pipeline facilities operated under 

multiple OPIDs. 

(ii) A change in the name of the 

operator; 

(iii) A change in the entity (e.g., 

company, municipality) responsible for 

operating an existing pipeline, pipeline 

segment, or pipeline facility; 

(iv) The acquisition or divestiture of 

50 or more miles of pipeline or pipeline 

system subject to this part; or 

(v) The acquisition or divestiture of an 

existing pipeline facility subject to this 

part. 

(d) Reporting. An operator must use 

the OPID issued by PHMSA for all 

reporting requirements covered under 

this subchapter and for submissions to 

the National Pipeline Mapping System. 

Issued in Washington, DC, on November 9, 

2010, under the authority delegated in 49 

CFR Part 1. 

Cynthia L. Quarterman, 

Administrator. 

[FR Doc. 2010–29087 Filed 11–24–10; 8:45 am] 

BILLING CODE 4910–60–P 


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